Piping Inspection Code - ismss.ruismss.ru/uploads/8-1-4.pdf · API 570 SECOND EDITION, OCTOBER 1998 ADDENDUM 1, FEBRUARY 2000 ... API publications necessarily address problems of

Piping Inspection Code

Inspection, Repair, Alteration, and Rerating of In-service Piping Systems

API 570SECOND EDITION, OCTOBER 1998ADDENDUM 1, FEBRUARY 2000ADDENDUM 2, DECEMBER 2001ADDENDUM 3, AUGUST 2003

Copyright American Petroleum Institute Provided by IHS under license with API Licensee=BP Amoco/5928366101

Not for Resale, 02/21/2006 14:10:23 MSTNo reproduction or networking permitted without license from IHS

--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

Piping Inspection Code

Inspection, Repair, Alteration, and Reratingof In-service Piping Systems

Downstream Segment

API 570SECOND EDITION, OCTOBER 1998ADDENDUM 1, FEBRUARY 2000ADDENDUM 2, DECEMBER 2001ADDENDUM 3, AUGUST 2003



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

SPECIAL NOTES

API publications necessarily address problems of a general nature. With respect to partic-ular circumstances, local, state, and federal laws and regulations should be reviewed.

API is not undertaking to meet the duties of employers, manufacturers, or suppliers towarn and properly train and equip their employees, and others exposed, concerning healthand safety risks and precautions, nor undertaking their obligations under local, state, or fed-eral laws.

Information concerning safety and health risks and proper precautions with respect to par-ticular materials and conditions should be obtained from the employer, the manufacturer orsupplier of that material, or the material safety data sheet.

Nothing contained in any API publication is to be construed as granting any right, byimplication or otherwise, for the manufacture, sale, or use of any method, apparatus, or prod-uct covered by letters patent. Neither should anything contained in the publication be con-strued as insuring anyone against liability for infringement of letters patent.

Generally, API standards are reviewed and revised, reaffirmed, or withdrawn at least everyfive years. Sometimes a one-time extension of up to two years will be added to this reviewcycle. This publication will no longer be in effect five years after its publication date as anoperative API standard or, where an extension has been granted, upon republication. Statusof the publication can be ascertained from the API Standards Department, [telephone (202)682-8000]. A catalog of API publications and materials is published annually and updatedquarterly by API, 1220 L Street, N.W., Washington, D.C. 20005.

This document was produced under API standardization procedures that ensure appropri-ate notification and participation in the developmental process and is designated as an APIstandard. Questions concerning the interpretation of the content of this standard or com-ments and questions concerning the procedures under which this standard was developedshould be directed in writing to the director of the Standards Department, American Petro-leum Institute, 1220 L Street, N.W., Washington, D.C. 20005. Requests for permission toreproduce or translate all or any part of the material published herein should also beaddressed to the director.

API standards are published to facilitate the broad availability of proven, sound engineer-ing and operating practices. These standards are not intended to obviate the need for apply-ing sound engineering judgment regarding when and where these standards should beutilized. The formulation and publication of API standards is not intended in any way toinhibit anyone from using any other practices.

Any manufacturer marking equipment or materials in conformance with the markingrequirements of an API standard is solely responsible for complying with all the applicablerequirements of that standard. API does not represent, warrant, or guarantee that such prod-ucts do in fact conform to the applicable API standard.

00

All rights reserved. No part of this work may be reproduced, stored in a retrieval system, or transmitted by any means, electronic, mechanical, photocopying, recording, or otherwise,

without prior written permission from the publisher. Contact the Publisher, API Publishing Services, 1220 L Street, N.W., Washington, D.C. 20005.

Copyright © 1998, 2000, 2001, 2003 American Petroleum Institute



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

FOREWORD

It is the intent of API to keep this publication up to date. All piping system owners andoperators are invited to report their experiences in the inspection and repair of piping sys-tems whenever such experiences may suggest a need for revising or expanding the practicesset forth in API 570.

This edition of API 570 supersedes all previous editions of API 570,

Piping InspectionCode: Inspection, Repair, Alteration, and Rerating of In-service Piping Systems.

Each edi-tion, revision, or addenda to this API standard may be used beginning with the date of issu-ance shown on the cover page for that edition, revision, or addenda. Each edition, revision,or addenda, to this API standard becomes effective six months after the date of issuance forequipment that is rerated, reconstructed, relocated, repaired, modified (altered), inspected,and tested per this standard. During the six-month time between the date of issuance of theedition, revision, or addenda and the effective date, the user shall specify to which edition,revision, or addenda, the equipment is to be, rerated, reconstructed, relocated, repaired, mod-ified (altered), inspected and tested.

API publications may be used by anyone desiring to do so. Every effort has been made bythe Institute to assure the accuracy and reliability of the data contained in them; however, theInstitute makes no representation, warranty, or guarantee in connection with this publicationand hereby expressly disclaims any liability or responsibility for loss or damage resultingfrom its use or for the violation of any federal, state, or municipal regulation with which thispublication may conflict.

Suggested revisions are invited and should be submitted to the director of the StandardsDepartment, American Petroleum Institute, 1220 L Street, N.W., Washington, D.C. 20005.

00

iii



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

CONTENTS

Page

1 SCOPE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-11.1 General Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-11.2 Specific Applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-11.3 Fitness-for-service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1

2 REFERENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1

3 DEFINITIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1

4 OWNER/USER INSPECTION ORGANIZATION . . . . . . . . . . . . . . . . . . . . . . . . . . 4-14.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-14.2 API Authorized Piping Inspector Qualification and Certification . . . . . . . . . . . 4-14.3 Responsibilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1

5 INSPECTION AND TESTING PRACTICES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-15.1 Risk-Based Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-15.2 Preparation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-15.3 Inspection for Specific Types of Corrosion and Cracking . . . . . . . . . . . . . . . . . 5-15.4 Types of Inspection and Surveillance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-65.5 Thickness Measurement Locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-75.6 Thickness Measurement Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-85.7 Pressure Testing of Piping Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-85.8 Material Verification and Traceability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-95.9 Inspection of Valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-95.10 Inspection of Welds In-service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-105.11 Inspection of Flanged Joints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-10

6 FREQUENCY AND EXTENT OF INSPECTION . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-16.1 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-16.2 Piping Service Classes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-16.3 Inspection Intervals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-26.4 Extent of Visual External and CUI Inspections. . . . . . . . . . . . . . . . . . . . . . . . . . 6-26.5 Extent of Thickness Measurement Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . 6-26.6 Extent of Small-Bore Auxiliary Piping, and

Threaded-Connections Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-3

7 INSPECTION DATA EVALUATION, ANALYSIS, AND RECORDING . . . . . . . 7-17.1 Corrosion Rate Determination. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-17.2 Maximum Allowable Working Pressure Determination. . . . . . . . . . . . . . . . . . . 7-17.3 Retirement Thickness Determination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-27.4 Assessment of Inspection Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-27.5 Piping Stress Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-27.6 Reporting and Records for Piping System Inspection . . . . . . . . . . . . . . . . . . . . 7-4

8 REPAIRS, ALTERATIONS, AND RERATING OF PIPING SYSTEMS . . . . . . . . 8-18.1 Repairs and Alterations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-18.2 Welding and Hot Tapping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-28.3 Rerating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-3

01

01

01

00

01

01

01

01

01

v



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

Page

9 INSPECTION OF BURIED PIPING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9-19.1 Types and Methods of Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9-19.2 Frequency and Extent of Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9-29.3 Repairs to Buried Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9-39.4 Records. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9-3

APPENDIX A INSPECTOR CERTIFICATION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1APPENDIX B TECHNICAL INQUIRIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1APPENDIX C EXAMPLES OF REPAIRS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-1APPENDIX D EXTERNAL INSPECTION

CHECKLIST FOR PROCESS PIPING. . . . . . . . . . . . . . . . . . . . . . . . . D-1

Figures5-1 Typical Injection Point Piping Circuit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-2C-1 Encirclement Repair Sleeve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-1C-2 Small Repair Patches. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-2

Tables6-1 Recommended Maximum Inspection Intervals . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-36-2 Recommended Extent of CUI Inspection Following Visual Inspection . . . . . . . . 6-37-1 Two Examples of the Calculation of Maximum Allowable

Working Pressure (MAWP) Illustrating the Use of the CorrosionHalf-Life Concept . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-3

9-1 Frequency of Inspection for Buried Piping Without EffectiveCathodic Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9-2

00

01

01

vi



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

1-1

Piping Inspection Code—Inspection, Repair, Alteration, and Rerating of In-service Piping Systems

1 Scope

1.1 GENERAL APPLICATION

1.1.1 Coverage

API 570 covers inspection, repair, alteration, and rerat-ing procedures for metallic piping systems that have beenin-service.

1.1.2 Intent

API 570 was developed for the petroleum refining andchemical process industries but may be used, where practi-cal, for any piping system. It is intended for use by organi-zations that maintain or have access to an authorizedinspection agency, a repair organization, and technicallyqualified piping engineers, inspectors, and examiners, allas defined in Section 3.

1.1.3 Limitations

API 570 shall not be used as a substitute for the originalconstruction requirements governing a piping system beforeit is placed in-service; nor shall it be used in conflict with anyprevailing regulatory requirements.

1.2 SPECIFIC APPLICATIONS

1.2.1 Included Fluid Services

Except as provided in 1.2.2, API 570 applies to piping sys-tems for process fluids, hydrocarbons, and similar flammableor toxic fluid services, such as the following:

a. Raw, intermediate, and finished petroleum products.

b. Raw, intermediate, and finished chemical products.

c. Catalyst lines.

d. Hydrogen, natural gas, fuel gas, and flare systems.

e. Sour water and hazardous waste streams above thresholdlimits, as defined by jurisdictional regulations.

f. Hazardous chemicals above threshold limits, as defined byjurisdictional regulations.

1.2.2 Excluded and Optional Piping Systems

The fluid services and classes of piping systems listedbelow are excluded from the specific requirements of API 570but may be included at the owner’s or user’s (owner/user’s)option.

a. Fluid services that are excluded or optional include thefollowing:

1. Hazardous fluid services below threshold limits, asdefined by jurisdictional regulations.2. Water (including fire protection systems), steam,steam-condensate, boiler feed water, and Category D fluidservices, as defined in ASME B31.3.

b. Classes of piping systems that are excluded or optional areas follows:

1. Piping systems on movable structures covered by juris-dictional regulations, including piping systems on trucks,ships, barges, and other mobile equipment.2. Piping systems that are an integral part or componentof rotating or reciprocating mechanical devices, such aspumps, compressors, turbines, generators, engines, andhydraulic or pneumatic cylinders where the primarydesign considerations and/or stresses are derived from thefunctional requirements of the device.3. Internal piping or tubing of fired heaters and boilers,including tubes, tube headers, return bends, externalcrossovers, and manifolds.4. Pressure vessels, heaters, furnaces, heat exchangers,and other fluid handling or processing equipment, includ-ing internal piping and connections for external piping.5. Plumbing, sanitary sewers, process waste sewers, andstorm sewers.6. Piping or tubing with an outside diameter not exceed-ing that of NPS

1

/

2

.7. Nonmetallic piping and polymeric or glass-lined piping.

1.3 FITNESS-FOR-SERVICE

This inspection code recognizes fitness-for-service conceptsfor evaluating in-service degradation of pressure containingcomponents. API RP 579 provides general requirements anddetailed assessment procedures for specific types of degrada-tion that are referenced in this code.

01



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

2-1

SECTION 2—REFERENCES

The most recent editions of the following standards, codes,and specifications are cited in this code.

API510

Pressure Vessel Inspection Code

Publ 2201

Procedures for Welding or Hot Tapping onEquipment Containing Flammables

RP 574

Inspection of Piping System Components

RP 578

Material Verification Program for New andExisting Piping Systems

RP 579

Fitness-for-service

RP 651

Cathodic Protection of AbovegroundPetroleum Storage Tanks

RP 750

Management of Process Hazards

Std 598

Valve Inspection and Testing

Guide for Inspection of Refinery Equipment, Chapter II

(This document will bereplaced by API RP 571,

Conditions Caus-ing Deterioration or Failures,

currentlyunder development.)

API 570

Inspector Certification Exam Body ofKnowledge

ASME

1

B16.34

Valves—Flanged, Threaded, and WeldingEnd

B31.3

Process Piping

B31G

Manual for Determining the RemainingStrength of Corroded Pipelines

Boiler and Pressure Vessel Code,

Section VIII

,

Divisions 1and 2;

Section IX

,

ASNT

2

SNT-TC-1A

Personnel Qualification and Certificationin Nondestructive Testing

CP-189

Standard for Qualification and Certifica-tion of Nondestructive Testing Personnel

ASTM

3

G57

Method for Field Measurement of SoilResistivity Using the Wenner Four-electrode Method

NACE

4

RP0169 C

ontrol of External Corrosion on Under-ground or Submerged Metallic PipingSystems

RP0170

Protection of Austenitic Stainless Steelsfrom Polythionic Acid Stress CorrosionCracking During Shutdown of RefineryEquipment

RP0274

High-voltage Electrical Inspection of Pipe-line Coatings Prior to Installation

RP0275

Application of Organic Coatings to theExternal Surface of Steel Pipe for Under-ground Service

NFPA

5

704

Identification of the Fire Hazards ofMaterials

1

ASME International, Three Park Avenue, New York, New York10016-5990, www.asme.org.

01

00

01

2

The American Society for Nondestructive Testing, 1711 ArlingateLane, P.O. Box 28518, Columbus, Ohio 43228-0518, www.asnt.org.

3

American Society for Testing and Materials, 100 Barr HarborDrive, West Conshohocken, Pennsylvania 19428-2959,www.astm.org.

4

NACE International, 440 South Creek Drive, Houston, Texas77084, www.nace.org.

5

National Fire Protection Association, 1 Batterymarch Park, P.O.Box 9101, Quincy, Massachusetts 02269-9101, www.nfpa.org.



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

3-1

SECTION 3—DEFINITIONS

For the purposes of this standard, the following definitionsapply.

3.1 alteration:

A physical change in any component thathas design implications affecting the pressure containingcapability or flexibility of a piping system beyond the scopeof its design. The following are not considered alterations:comparable or duplicate replacement; the addition of anyreinforced branch connection equal to or less than the size ofexisting reinforced branch connections; and the addition ofbranch connections not requiring reinforcement.

3.2 applicable code:

The code, code section, or other rec-ognized and generally accepted engineering standard or prac-tice to which the piping system was built or which is deemedby the owner or user or the piping engineer to be most appro-priate for the situation, including but not limited to the latestedition of ASME B31.3.

3.3 ASME B31.3:

A shortened form of ASME B31.3,

Pro-cess Piping

, published by the American Society of Mechani-cal Engineers. ASME B31.3 is written for design andconstruction of piping systems. However, most of the techni-cal requirements on design, welding, examination, and materi-als also can be applied in the inspection, rerating, repair, andalteration of operating piping systems. When ASME B31.3cannot be followed because of its new construction coverage(such as revised or new material specifications, inspectionrequirements, certain heat treatments, and pressure tests), thepiping engineer or inspector shall be guided by API 570 in lieuof strict conformity to ASME B31.3. As an example of intent,the phrase “principles of ASME B31.3” has been employed inAPI 570, rather than “in accordance with ASME B31.3.”

3.4 authorized inspection agency:

Defined as any ofthe following:

a. The inspection organization of the jurisdiction in whichthe piping system is used.b. The inspection organization of an insurance company thatis licensed or registered to write insurance for piping systems. c. An owner or user of piping systems who maintains aninspection organization for activities relating only to his equip-ment and not for piping systems intended for sale or resale. d. An independent inspection organization employed by orunder contract to the owner or user of piping systems that areused only by the owner or user and not for sale or resale.e. An independent inspection organization licensed or recog-nized by the jurisdiction in which the piping system is usedand employed by or under contract to the owner or user.

3.5 authorized piping inspector:

An employee of anauthorized inspection agency who is qualified and certified toperform the functions specified in API 570. A nondestructive(NDE) examiner is not required to be an authorized piping

inspector. Whenever the term inspector is used in API 570, itrefers to an authorized piping inspector.

3.6 auxiliary piping:

Instrument and machinery piping,typically small-bore secondary process piping that can be iso-lated from primary piping systems. Examples include flushlines, seal oil lines, analyzer lines, balance lines, buffer gaslines, drains, and vents.

3.7 critical check valves:

Valves that have been identifiedas vital to process safety and must operate reliably in order toavoid the potential for hazardous events or substantial conse-quences should a leak occur.

3.8 CUI:

Corrosion under insulation, including stress corro-sion cracking under insulation.

3.9 deadlegs:

Components of a piping system that nor-mally have no significant flow. Examples include the follow-ing: blanked branches, lines with normally closed blockvalves, lines with one end blanked, pressurized dummy sup-port legs, stagnant control valve bypass piping, spare pumppiping, level bridles, relief valve inlet and outlet header pip-ing, pump trim bypass lines, high-point vents, sample points,drains, bleeders, and instrument connections.

3.10 defect:

An imperfection of a type or magnitudeexceeding the acceptable criteria.

3.11 design temperature of a piping system com-ponent:

The temperature at which, under the coincidentpressure, the greatest thickness or highest component rating isrequired. It is the same as the design temperature defined inASME B31.3 and other code sections and is subject to thesame rules relating to allowances for variations of pressure ortemperature or both. Different components in the same pipingsystem or circuit may have different design temperatures. Inestablishing the design temperature, consideration shall begiven to process fluid temperatures, ambient temperatures,heating and cooling media temperatures, and insulation.

3.12 examiner:

A person who assists the inspector by per-forming specific nondestructive examination (NDE) on pip-ing system components but does not evaluate the results ofthose examinations in accordance with API 570, unless spe-cifically trained and authorized to do so by the owner or user.The examiner need not be qualified in accordance with API570 or be an employee of the owner or user but shall betrained and qualified in the applicable procedures in whichthe examiner is involved. In some cases, the examiner may berequired to hold other certifications as necessary to satisfyowner or user requirements. Examples of other certificationthat may be required are SNT-TC-1A or CP-189; or AWS

1

1

American Welding Society, 550 N.W. LeJeune Road, Miami, Flor-ida 33135.



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

3-2 API 570

Welding Inspector certification. The examiner’s employershall maintain certification records of the examinersemployed, including dates and results of personnel qualifica-tions, and shall make them available to the inspector.

3.13 hold point:

A point in the repair or alteration processbeyond which work may not proceed until the requiredinspection has been performed and documented.

3.14 imperfections:

Flaws or other discontinuities notedduring inspection that may be subject to acceptance criteriaduring an engineering and inspection analysis.

3.15 indication:

A response or evidence resulting from theapplication of a nondestructive evaluation technique.

3.16 injection point:

Locations where relatively smallquantities of materials are injected into process streams tocontrol chemistry or other process variables. Injection pointsdo not include locations where two process streams join(mixing tees). Examples of injection points include chlorinein reformers, water injection in overhead systems, polysulfideinjection in catalytic cracking wet gas, antifoam injections,inhibitors, and neutralizers.

3.17 in-service:

Refers to piping systems that have beenplaced in operation, as opposed to new construction prior tobeing placed in service.

3.18 inspector:

An authorized piping inspector.

3.19 jurisdiction:

A legally constituted government admin-istration that may adopt rules relating to piping systems.

3.20 level bridle:

A level gauge glass piping assemblyattached to a vessel.

3.21 maximum allowable working pressure:(MAWP):

The maximum internal pressure permitted in thepiping system for continued operation at the most severe con-dition of coincident internal or external pressure and tempera-ture (minimum or maximum) expected during service. It is thesame as the design pressure, as defined in ASME B31.3 andother code sections, and is subject to the same rules relating toallowances for variations of pressure or temperature or both.

3.22 mixing tee:

A piping component that combines twoprocess streams of differing composition and/or temperature.

3.23 MT:

Magnetic-particle testing.

3.24 NDE:

Nondestructive examination.

3.25 NPS:

Nominal pipe size (followed, when appropri-ate, by the specific size designation number without aninch symbol).

3.26 on-stream:

Piping containing any amount of processfluid.

3.27 owner/user:

An owner or user of piping systems whoexercises control over the operation, engineering, inspection,repair, alteration, testing, and rerating of those piping systems.

3.28 owner/user inspector:

An authorized inspectoremployed by an owner/user who has qualified either by writ-ten examination under the provisions of Section 4 andAppendix A of API 570 or has qualified under the provisionsof A.2, and who meets the requirements of the jurisdiction.

3.29 PT:

A

liquid-penetrant testing.

3.30 pipe:

A pressure-tight cylinder used to convey a fluidor to transmit a fluid pressure and is ordinarily designated“pipe” in applicable material specifications. (Materials desig-nated “tube” or “tubing” in the specifications are treated aspipe when intended for pressure service.)

3.31 piping circuit:

A section of piping that has all pointsexposed to an environment of similar corrosivity and that is ofsimilar design conditions and construction material. Complexprocess units or piping systems are divided into piping cir-cuits to manage the necessary inspections, calculations, andrecord keeping. When establishing the boundary of a particu-lar piping circuit, the inspector may also size it to provide apractical package for record keeping and performing fieldinspection.

3.32 piping engineer:

One or more persons or organiza-tions acceptable to the owner or user who are knowledgeableand experienced in the engineering disciplines associated withevaluating mechanical and material characteristics affectingthe integrity and reliability of piping components and systems.The piping engineer, by consulting with appropriate special-ists, should be regarded as a composite of all entities neces-sary to properly address a technical requirement.

3.33 piping system:

An assembly of interconnected pip-ing that is subject to the same set or sets of design conditionsand is used to convey, distribute, mix, separate, discharge,meter, control, or snub fluid flows. Piping system alsoincludes pipe-supporting elements but does not include sup-port structures, such as structural frames and foundations.

3.34 primary process piping:

Process piping in normal,active service that cannot be valved off or, if it were valvedoff, would significantly affect unit operability. Primary pro-cess piping normally includes all process piping greater thanNPS 2.

3.35 PWHT:

postweld heat treatment.

3.36 renewal:

Activity that discards an existing componentand replaces it with new or existing spare materials of thesame or better qualities as the original component.

3.37 repair:

The work necessary to restore a piping systemto a condition suitable for safe operation at the design condi-tions. If any of the restorative changes result in a change of



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

P

IPING

I

NSPECTION

C

ODE

—I

NSPECTION

, R

EPAIR

, A

LTERATION

,

AND

R

ERATING

OF

I

N

-S

ERVICE

P

IPING

S

YSTEMS

3-3

design temperature or pressure, the requirements for reratingalso shall be satisfied. Any welding, cutting, or grinding oper-ation on a pressure-containing piping component not specifi-cally considered an alteration is considered a repair.

3.38 repair organization:

Any of the following:

a. An owner or user of piping systems who repairs or altershis or her own equipment in accordance with API 570.

b. A contractor whose qualifications are acceptable to theowner or user of piping systems and who makes repairs oralterations in accordance with API 570.

c. One who is authorized by, acceptable to, or otherwise notprohibited by the jurisdiction and who makes repairs inaccordance with API 570.

3.39 rerating:

A change in either or both the design tem-perature or the maximum allowable working pressure of apiping system. A rerating may consist of an increase, adecrease, or a combination of both. Derating below originaldesign conditions is a means to provide increased corrosionallowance.

3.40 secondary process piping:

Small-bore (less thanor equal to NPS 2) process piping downstream of normallyclosed block valves.

3.41 small-bore piping (SBP):

Piping that is less than orequal to NPS 2.

3.42 soil-to-air (S/A) interface:

An area in which exter-nal corrosion may occur on partially buried pipe. The zone ofthe corrosion will vary depending on factors such as mois-ture, oxygen content of the soil, and operating temperature.The zone generally is considered to be from 12 inches (305mm) below to 6 inches (150 mm) above the soil surface. Piperunning parallel with the soil surface that contacts the soil isincluded.

3.43 spool:

A section of piping encompassed by flanges orother connecting fittings such as unions.

3.44 temper embrittlement:

A loss of ductility and notchtoughness in susceptible low-alloy steels, such as 1

1

/

4

Cr and2

1

/

4

Cr, due to prolonged exposure to high-temperature ser-vice [700°F – 1070°F (370°C – 575°C)].

3.45 temporary repairs:

Repairs made to piping systemsin order to restore sufficient integrity to continue safe opera-tion until permanent repairs can be scheduled and accom-plished within a time period acceptable to the inspector orpiping engineer.

3.46 test point:

An area defined by a circle having a diam-eter not greater than 2 inches (50 mm) for a line diameter notexceeding 10 inches (250 mm), or not greater than 3 inches(75 mm) for larger lines. Thickness readings may be averagedwithin this area. A test point shall be within a thickness mea-surement location.

3.47 thickness measurement locations (TMLs):

Des-ignated areas on piping systems where periodic inspectionsand thickness measurements are conducted.

3.48 WFMT:

Wet fluorescent magnetic-particle testing.

3.49 alloy material:

Any metallic material (includingwelding filler materials) that contains alloying elements, suchas chromium, nickel, or molybdenum, which are intentionallyadded to enhance mechanical or physical properties and/orcorrosion resistance.

3.50 material verification program:

A documentedquality assurance procedure used to assess metallic alloymaterials (including weldments and attachments where speci-fied) to verify conformance with the selected or specified alloymaterial designated by the owner/user. This program mayinclude a description of methods for alloy material testing,physical component marking, and program record-keeping.

3.51 positive material identification (PMI) testing:

Any physical evaluation or test of a material to confirm thatthe material which has been or will be placed into service isconsistent with the selected or specified alloy material desig-nated by the owner/user. These evaluations or tests may pro-vide qualitative or quantitative information that is sufficient toverify the nominal alloy composition.

3.52 fitness-for-service assessment:

A methodologywhereby flaws and conditions contained within a structure areassessed in order to determine the integrity of the structure forcontinued service.

3.53 industry-qualified UT shear wave examiner:

Aperson who possesses an ultrasonic shear wave qualificationfrom API or an equivalent qualification approved by theowner/user.

3.54 off-site piping:

Piping systems not included withinthe plot (battery) limits of a process unit, such as, a hydroc-racker, an ethylene cracker or a crude unit. Examples of off-site piping include tank farm piping and other lower conse-quence piping outside the limits of the process unit.

3.55 on-site piping:

Piping systems included within theplot limits of process units, such as, a hydrocracker, an ethyl-ene cracker, or a crude unit.

00

01

03



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

4-1

SECTION 4—OWNER/USER INSPECTION ORGANIZATION

4.1 GENERAL

An owner/user of piping systems shall exercise control ofthe piping system inspection program, inspection frequen-cies, and maintenance and is responsible for the function ofan authorized inspection agency in accordance with the provi-sions of API 570. The owner/user inspection organizationalso shall control activities relating to the rerating, repair, andalteration of its piping systems.

4.2 API AUTHORIZED PIPING INSPECTOR QUALIFICATION AND CERTIFICATION

Authorized piping inspectors shall have education andexperience in accordance with Appendix A of this inspectioncode. Authorized piping inspectors shall be certified by theAmerican Petroleum Institute in accordance with the provi-sions of Appendix A. Whenever the term inspector is used inthis document, it refers to an authorized piping inspector.

4.3 RESPONSIBILITIES

4.3.1 Owner/User

An owner/user organization is responsible for developing,documenting, implementing, executing, and assessing pipinginspection systems and inspection procedures that will meetthe requirements of this inspection code. These systems andprocedures will be contained in a quality assurance inspectionmanual or written procedures and shall include:

a. Organization and reporting structure for inspectionpersonnel.b. Documenting and maintaining inspection and qualityassurance procedures.c. Documenting and reporting inspection and test results.d. Corrective action for inspection and test results.e. Internal auditing for compliance with the quality assur-ance inspection manual.f. Review and approval of drawings, design calculations, andspecifications for repairs, alterations, and reratings.g. Ensuring that all jurisdictional requirements for pipinginspection, repairs, alterations, and rerating are continuouslymet.h. Reporting to the authorized piping inspector any processchanges that could affect piping integrity.i. Training requirements for inspection personnel regardinginspection tools, techniques, and technical knowledge base.j. Controls necessary so that only qualified welders and pro-cedures are used for all repairs and alterations.

k. Controls necessary so that only qualified nondestructiveexamination (NDE) personnel and procedures are utilized.l. Controls necessary so that only materials conforming tothe applicable section of the ASME Code are utilized forrepairs and alterations.m. Controls necessary so that all inspection measurement andtest equipment are properly maintained and calibrated.n. Controls necessary so that the work of contract inspectionor repair organizations meet the same inspection require-ments as the owner/user organization.o. Internal auditing requirements for the quality control sys-tem for pressure-relieving devices.

4.3.2 Piping Engineer

The piping engineer is responsible to the owner/user foractivities involving design, engineering review, analysis, orevaluation of piping systems covered by API 570.

4.3.3 Repair Organization

The repair organization shall be responsible to theowner/user and shall provide the materials, equipment,quality control, and workmanship necessary to maintainand repair the piping systems in accordance with therequirements of API 570.

4.3.4 Authorized Piping Inspector

When inspections, repairs, or alterations are being con-ducted on piping systems, an API-authorized piping inspectorshall be responsible to the owner/user for determining that therequirements of API 570 on inspection, examination, andtesting are met, and shall be directly involved in the inspec-tion activities. The API-authorized piping inspector may beassisted in performing visual inspections by other properlytrained and qualified individuals, who may or may not be cer-tified piping inspectors. Personnel performing nondestructiveexaminations shall meet the qualifications identified in 3.12,but need not be API-authorized piping inspectors. However,all examination results must be evaluated and accepted by theAPI-authorized piping inspector.

4.3.5 Other Personnel

Operating, maintenance, or other personnel who have spe-cial knowledge or expertise related to particular piping sys-tems shall be responsible for promptly making the inspector orpiping engineer aware of any unusual conditions that maydevelop and for providing other assistance, where appropriate.



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

5-1

SECTION 5—INSPECTION AND TESTING PRACTICES

5.1 RISK-BASED INSPECTION

Identifying and evaluating potential degradation mecha-nisms are important steps in an assessment of the likelihoodof a piping failure. However, adjustments to inspection strat-egy and tactics to account for consequences of a failureshould also be considered. Combining the assessment of like-lihood of failure and the consequence of failure are essentialelements of risk-based inspection (RBI).

When the owner/user chooses to conduct a RBI assessmentit must include a systematic evaluation of both the likelihoodof failure and the associated consequence of failure, in accor-dance with API RP 580. The likelihood assessment must bebased on all forms of degradation that could reasonably beexpected to affect piping circuits in any particular service.Examples of those degradation mechanisms include: internalor external metal loss from an identified form of corrosion(localized or general), all forms of cracking including hydro-gen assisted and stress corrosion cracking (from the inside oroutside surfaces of piping), and any other forms of metallur-gical, corrosion, or mechanical degradation, such as fatigue,embrittlement, creep, etc. Additionally, the effectiveness ofthe inspection practices, tools, and techniques utilized forfinding the expected and potential degradation mechanismsmust be evaluated. This likelihood of failure assessmentshould be repeated each time equipment or process changesare made that could significantly affect degradation rates orcause premature failure of the piping.

Other factors that should be considered in a RBI assess-ment conducted in accordance with API RP 580 include:appropriateness of the materials of construction; piping cir-cuit design conditions, relative to operating conditions;appropriateness of the design codes and standards utilized;effectiveness of corrosion monitoring programs; and the qual-ity of maintenance and inspection Quality Assurance/QualityControl programs. Equipment failure data and informationwill also be important information for this assessment. Theconsequence assessment must consider the potential incidentsthat may occur as a result of fluid release, including explo-sion, fire, toxic exposure, environmental impact, and otherhealth effects associated with a failure of piping.

It is essential that all RBI assessments be thoroughly docu-mented in accordance with API RP 580, clearly defining allthe factors contributing to both the likelihood and conse-quence of a piping failure.

5.2 PREPARATION

Because of the products carried in piping systems, safetyprecautions are important when the system is inspected, par-ticularly if it is opened for examining internal surfaces.

Procedures for segregating piping systems, installingblanks (blinds), and testing tightness should be an integralpart of safety practices. Appropriate safety precautions shall

be taken before any piping system is opened and before sometypes of external inspection are performed. In general, thesection of piping to be opened should be isolated from allsources of harmful liquids, gases, or vapors and purged toremove all oil and toxic or flammable gases and vapors.

Before starting inspection, inspection personnel shouldobtain permission to work in the vicinity from operating per-sonnel responsible for the piping system.

Protective equipment shall be worn when required by regu-lations or by the owner/user.

Nondestructive testing equipment used for inspection issubject to the operating facility’s safety requirements for elec-trical equipment.

In general, inspectors should familiarize themselves withprior inspection results and repairs in the piping systems forwhich they are responsible. In particular, they should brieflyreview the history of individual piping systems before makingany of the inspections required by API 570. (See Section 8 ofAPI RP 574 for supplementary recommended practices.) Ageneral overview of the types of deterioration and failuremodes experienced by pressure containing equipment is pro-vided in API RP 579, Appendix G.

5.3 INSPECTION FOR SPECIFIC TYPES OF CORROSION AND CRACKING

Note: For more thorough and complete information, see API IREChapter II.

Each owner/user should provide specific attention to theneed for inspection of piping systems that are susceptible tothe following specific types and areas of deterioration:

a. Injection points.b. Deadlegs.c. Corrosion under insulation (CUI).d. Soil-to-air (S/A) interfaces.e. Service specific and localized corrosion.f. Erosion and corrosion/erosion.g. Environmental cracking.h. Corrosion beneath linings and deposits.i. Fatigue cracking.j. Creep cracking.k. Brittle fracture.l. Freeze damage.

Other areas of concern are noted in IRE Chapter II, andSection 6 of API RP 574.

5.3.1 Injection Points

Injection points are sometimes subject to accelerated orlocalized corrosion from normal or abnormal operating con-ditions. Those that are may be treated as separate inspectioncircuits, and these areas need to be inspected thoroughly on aregular schedule.

03

03

03

01

00



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

5-2 API 570

When designating an injection point circuit for the purposesof inspection, the recommended upstream limit of the injec-tion point circuit is a minimum of 12 inches (300 mm) or threepipe diameters upstream of the injection point, whichever isgreater. The recommended downstream limit of the injectionpoint circuit is the second change in flow direction past theinjection point, or 25 feet (7.6 m) beyond the first change inflow direction, whichever is less. In some cases, it may bemore appropriate to extend this circuit to the next piece ofpressure equipment, as shown in Figure 5-1.

The selection of thickness measurement locations (TMLs)within injection point circuits subject to localized corrosionshould be in accordance with the following guidelines:

a. Establish TMLs on appropriate fittings within the injectionpoint circuit.b. Establish TMLs on the pipe wall at the location ofexpected pipe wall impingement of injected fluid.c. TMLs at intermediate locations along the longer straightpiping within the injection point circuit may be required.d. Establish TMLs at both the upstream and downstream lim-its of the injection point circuit.

The preferred methods of inspecting injection points areradiography and/or ultrasonics, as appropriate, to establishthe minimum thickness at each TML. Close grid ultrasonicmeasurements or scanning may be used, as long as tempera-tures are appropriate.

For some applications, it is beneficial to remove pipingspools to facilitate a visual inspection of the inside surface.However, thickness measurements will still be required todetermine the remaining thickness.

During periodic scheduled inspections, more extensiveinspection should be applied to an area beginning 12 inches(300 mm) upstream of the injection nozzle and continuing forat least ten pipe diameters downstream of the injection point.Additionally, measure and record the thickness at all TMLswithin the injection point circuit.

5.3.2 Deadlegs

The corrosion rate in deadlegs can vary significantly fromadjacent active piping. The inspector should monitor wallthickness on selected deadlegs, including both the stagnant

Figure 5-1—Typical Injection Point Piping Circuit

or 12" minimum,whichever isgreater

Overhead vapor line

Distillationcolumn

Injection pointpiping circuit

3D

Overheadcondensers

**

**

*

*

*

*Typical thickness measurementlocations (TMLs) within injectionpoint circuits

Injectionpoint



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

P

IPING

I

NSPECTION

C

ODE

—I

NSPECTION

, R

EPAIR

, A

LTERATION

,

AND

R

ERATING

OF

I

N

-S

ERVICE

P

IPING

S

YSTEMS

5-3

end and at the connection to an active line. In hot piping sys-tems, the high-point area may corrode due to convective cur-rents set up in the deadleg. Consideration should be given toremoving deadlegs that serve no further process purpose.

5.3.3 Corrosion Under Insulation

External inspection of insulated piping systems shouldinclude a review of the integrity of the insulation system forconditions that could lead to corrosion under insulation (CUI)and for signs of ongoing CUI. Sources of moisture mayinclude rain, water leaks, condensation, and deluge systems.The most common forms of CUI are localized corrosion ofcarbon steel and chloride stress corrosion cracking of austen-itic stainless steels.

This section provides guidelines for identifying potentialCUI areas for inspection. The extent of a CUI inspection pro-gram may vary depending on the local climate—warmermarine locations may require a very active program; whereascooler, drier, mid-continent locations may not need as exten-sive a program.

5.3.3.1 Insulated Piping Systems Susceptible to CUI

Certain areas and types of piping systems are potentiallymore susceptible to CUI, including the following:

a. Areas exposed to mist overspray from cooling watertowers.

b. Areas exposed to steam vents.

c. Areas exposed to deluge systems.

d. Areas subject to process spills, ingress of moisture, or acidvapors.

e. Carbon steel piping systems, including those insulatedfor personnel protection, operating between 25°F–250°F(–4°C–120°C). CUI is particularly aggressive where oper-ating temperatures cause frequent or continuouscondensation and re-evaporation of atmospheric moisture.

f. Carbon steel piping systems that normally operate in-ser-vice above 250°F (120°C) but are in intermittent service.

g. Deadlegs and attachments that protrude from insulatedpiping and operate at a different temperature than the operat-ing temperature of the active line.

h. Austenitic stainless steel piping systems operatingbetween 150°F–400°F (65°C–204°C). (These systems aresusceptible to chloride stress corrosion cracking.)

i. Vibrating piping systems that have a tendency to inflictdamage to insulation jacketing providing a path for wateringress.

j. Steam traced piping systems that may experience tracingleaks, especially at tubing fittings beneath the insulation.

k. Piping systems with deteriorated coatings and/orwrappings.

5.3.3.2 Common Locations on Piping Systems Susceptible to CUI

The areas of piping systems listed in 5.3.3.1 may have spe-cific locations within them that are more susceptible to CUI,including the following:

a. All penetrations or breaches in the insulation jacketingsystems, such as:

1. Deadlegs (vents, drains, and other similar items).2. Pipe hangers and other supports.3. Valves and fittings (irregular insulation surfaces).4. Bolted-on pipe shoes.5. Steam tracer tubing penetrations.

b. Termination of insulation at flanges and other pipingcomponents.c. Damaged or missing insulation jacketing.d. Insulation jacketing seams located on the top of horizontalpiping or improperly lapped or sealed insulation jacketing.e. Termination of insulation in a vertical pipe.f. Caulking that has hardened, has separated, or is missing.g. Bulges or staining of the insulation or jacketing system ormissing bands. (Bulges may indicate corrosion productbuildup.)h. Low points in piping systems that have a known breach inthe insulation system, including low points in long unsup-ported piping runs.i. Carbon or low-alloy steel flanges, bolting, and other com-ponents under insulation in high-alloy piping systems.

Locations where insulation plugs have been removed topermit piping thickness measurements on insulated pipingshould receive particular attention. These plugs should bepromptly replaced and sealed. Several types of removableplugs are commercially available that permit inspection andidentification of inspection points for future reference.

5.3.4 Soil-to-Air Interface

Soil-to-air (S/A) interfaces for buried piping without ade-quate cathodic protection shall be included in scheduledexternal piping inspections. Inspection at grade should checkfor coating damage, bare pipe, and pit depth measurements. Ifsignificant corrosion is noted, thickness measurements andexcavation may be required to assess whether the corrosion islocalized to the S/A interface or may be more pervasive to theburied system. Thickness readings at S/A interfaces mayexpose the metal and accelerate corrosion if coatings andwrappings are not properly restored. If the buried piping hassatisfactory cathodic protection as determined by monitoringin accordance with Section 9, excavation is required only ifthere is evidence of coating or wrapping damage. If the buriedpiping is uncoated at grade, consideration should be given toexcavating 6 inches to 12 inches (150 mm to 300 mm) deep toassess the potential for hidden damage.

At concrete-to-air and asphalt-to-air interfaces of buriedpiping without cathodic protection, the inspector should look



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

5-4 API 570

for evidence that the caulking or seal at the interface has dete-riorated and allowed moisture ingress. If such a conditionexists on piping systems over 10 years old, it may be neces-sary to inspect for corrosion beneath the surface beforeresealing the joint.

5.3.5 Service-Specific and Localized Corrosion

An effective inspection program includes the followingthree elements, which help identify the potential for service-specific and localized corrosion and select appropriate TMLs:

a. An inspector with knowledge of the service and wherecorrosion is likely to occur.b. Extensive use of nondestructive examination (NDE).c. Communication from operating personnel when processupsets occur that may affect corrosion rates.

A few examples of where this type of corrosion might beexpected to occur include the following:

a. Downstream of injection points and upstream of productseparators, such as in hydroprocess reactor effluent lines.b. Dew-point corrosion in condensing streams, such as over-head fractionation.c. Unanticipated acid or caustic carryover from processesinto nonalloyed piping systems or caustic carryover into steelpiping systems that are not postweld heat treated.d. Ammonium salt condensation locations in hydroprocessstreams.e. Mixed-phase flow and turbulent areas in acidic systems.f. Mixed grades of carbon steel piping in hot corrosive oilservice [450°F (230°C) or higher temperature and sulfur con-tent in the oil greater than 0.5 percent by weight]. Note thatnonsilicon killed steel pipe, such as A-53 and API 5L, maycorrode at higher rates than does silicon killed steel pipe, suchas A-106, especially in high-temperature sulfidicenvironments.g. Underdeposit corrosion in slurries, crystallizing solutions,or coke producing fluids.h. Chloride carryover in catalytic reformer regenerationsystems.i. Hot-spot corrosion on piping with external heat tracing. Inservices that become much more corrosive to the piping withincreased temperature, such as caustic in carbon steel, corro-sion or stress corrosion cracking (SCC) can occur at hot spotsthat develop under low-flow conditions.

5.3.6 Erosion and Corrosion/Erosion

Erosion can be defined as the removal of surface materialby the action of numerous individual impacts of solid or liquidparticles. It can be characterized by grooves, rounded holes,waves, and valleys in a directional pattern. Erosion usuallyoccurs in areas of turbulent flow, such as at changes of direc-tion in a piping system or downstream of control valves wherevaporization may take place. Erosion damage is usuallyincreased in streams with large quantities of solid or liquid

particles flowing at high velocities. A combination of corro-sion and erosion (corrosion/erosion) results in significantlygreater metal loss than can be expected from corrosion or ero-sion alone. This type of corrosion occurs at high-velocity andhigh-turbulence areas.

Examples of places to inspect include the following:

a. Downstream of control valves, especially when flashing isoccurring.b. Downstream of orifices.c. Downstream of pump discharges.d. At any point of flow direction change, such as the insideand outside radii of elbows.e. Downstream of piping configurations (such as welds, ther-mowells, and flanges) that produce turbulence, particularly invelocity sensitive systems such as ammonium hydrosulfideand sulfuric acid systems.

Areas suspected of having localized corrosion/erosionshould be inspected using appropriate NDE methods that willyield thickness data over a wide area, such as ultrasonic scan-ning, radiographic profile, or eddy current.

5.3.7 Environmental Cracking

Piping system construction materials are normally selectedto resist the various forms of stress corrosion cracking (SCC).However, some piping systems may be susceptible to envi-ronmental cracking due to upset process conditions, CUI,unanticipated condensation, or exposure to wet hydrogen sul-fide or carbonates.

Examples of environmental cracking include:

a. Chloride SCC of austenitic stainless steels due to moistureand chlorides under insulation, under deposits, under gaskets,or in crevices.b. Polythionic acid SCC of sensitized austenitic alloy steelsdue to exposure to sulfide, moisture condensation, or oxygen.c. Caustic SCC (sometimes known as causticembrittlement).d. Amine SCC in piping systems that are not stress relieved.e. Carbonate SCC.f. SCC in environments where wet hydrogen sulfide exists,such as systems containing sour water.g. Hydrogen blistering and hydrogen induced cracking (HIC)damage.

When the inspector suspects or is advised that specific cir-cuits may be susceptible to environmental cracking, theinspector should schedule supplemental inspections. Suchinspections can take the form of surface NDE [liquid-pene-trant testing (PT), or wet fluorescent magnetic-particle testing(WFMT)], or ultrasonics (UT). Where available, suspectspools may be removed from the piping system and split openfor internal surface examination.

If environmental cracking is detected during internalinspection of pressure vessels and the piping is consideredequally susceptible, the inspector should designate appropriate



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

P

IPING

I

NSPECTION

C

ODE

—I

NSPECTION

, R

EPAIR

, A

LTERATION

,

AND

R

ERATING

OF

I

N

-S

ERVICE

P

IPING

S

YSTEMS

5-5

piping spools upstream and downstream of the pressure vesselfor environmental cracking inspection. When the potential forenvironmental cracking is suspected in piping circuits, inspec-tion of selected spools should be scheduled prior to an upcom-ing turnaround. Such inspection should provide informationuseful in forecasting turnaround maintenance.

5.3.8 Corrosion Beneath Linings and Deposits

If external or internal coatings, refractory linings, and cor-rosion-resistant linings are in good condition and there is noreason to suspect a deteriorated condition behind them, it isusually not necessary to remove them for inspection of thepiping system.

The effectiveness of corrosion-resistant linings is greatlyreduced due to breaks or holes in the lining. The liningsshould be inspected for separation, breaks, holes, and blisters.If any of these conditions are noted, it may be necessary toremove portions of the internal lining to investigate the effec-tiveness of the lining and the condition of the metal pipingbeneath the lining. Alternatively, ultrasonic inspection fromthe external surface can be used to measure wall thicknessand detect separation, holes, and blisters.

Refractory linings may spill or crack in-service with orwithout causing any significant problems. Corrosion beneathrefractory linings can result in separation and bulging of therefractory. If bulging or separation of the refractory lining isdetected, portions of the refractory may be removed to permitinspection of the piping beneath the refractory. Otherwise,ultrasonic thickness measurements may be made from theexternal metal surface.

Where operating deposits, such as coke, are present on apipe surface, it is particularly important to determine whethersuch deposits have active corrosion beneath them. This mayrequire a thorough inspection in selected areas. Larger linesshould have the deposits removed in selected critical areas forspot examination. Smaller lines may require that selectedspools be removed or that NDE methods, such as radiogra-phy, be performed in selected areas.

5.3.9 Fatigue Cracking

Fatigue cracking of piping systems may result from exces-sive cyclic stresses that are often well below the static yieldstrength of the material. The cyclic stresses may be imposedby pressure, mechanical, or thermal means and may result inlow-cycle or high-cycle fatigue. The onset of low-cyclefatigue cracking is often directly related to the number ofheat-up and cool-down cycles experienced. Excessive pipingsystem vibration (such as machine or flow-induced vibra-tions) also can cause high-cycle fatigue damage. (See 5.4.4for vibrating piping surveillance requirements and 7.5 fordesign requirements associated with vibrating piping.)

Fatigue cracking can typically be first detected at points ofhigh-stress intensification such as branch connections. Loca-tions where metals having different coefficients of thermal

expansion are joined by welding may be susceptible to ther-mal fatigue. (See 6.6.3 for fatigue considerations relative tothreaded connections.) Preferred NDE methods of detectingfatigue cracking include liquid-penetrant testing (PT) or mag-netic-particle testing (MT). Acoustic emission also may beused to detect the presence of cracks that are activated by testpressures or stresses generated during the test.

It is important that the owner/user and the inspector under-stand that fatigue cracking is likely to cause piping failurebefore it is detected with any NDE methods. Of the totalnumber of fatigue cycles required to produce a failure, thevast majority are required to initiate a crack and relativelyfewer cycles are required to propagate the crack to failure.Therefore, proper design and installation in order to preventthe initiation of fatigue cracking are important.

5.3.10 Creep Cracking

Creep is dependent on time, temperature, and stress. Creepcracking may eventually occur at design conditions, sincesome piping code allowable stresses are in the creep range.Cracking is accelerated by creep and fatigue interaction whenoperating conditions in the creep range are cyclic. The inspec-tor should pay particular attention to areas of high stress con-centration. If excessive temperatures are encountered,mechanical property and microstructural changes in metalsalso may take place, which may permanently weaken equip-ment. Since creep is dependent on time, temperature, andstress, the actual or estimated levels of these parameters shallbe used in any evaluations. An example of where creep crack-ing has been experienced in the industry is in 1

1

/

4

Cr steelsabove 900°F (480°C).

NDE methods of detecting creep cracking include liquid-penetrant testing, magnetic-particle testing, ultrasonic testing,radiographic testing, and in-situ metallography. Acousticemission testing also may be used to detect the presence ofcracks that are activated by test pressures or stresses gener-ated during the test.

5.3.11 Brittle Fracture

Carbon, low-alloy, and other ferritic steels may be suscepti-ble to brittle failure at or below ambient temperatures. Brittlefracture usually is not a concern with relatively thin-wall pip-ing. Most brittle fractures have occurred on the first applica-tion of a particular stress level (that is, the first hydrotest oroverload) unless critical defects are introduced during service.The potential for a brittle failure shall be considered whenrehydrotesting or more carefully evaluated when testingequipment pneumatically or when adding any other additionalloads. Special attention should be given to low-alloy steels(especially 2

1

/

4

Cr-1 Mo material), because they may be proneto temper embrittlement, and to ferritic stainless steels.

API RP 579, Section 3 provides procedures for the assess-ment of equipment for resistance to brittle fracture. 01



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

5-6 API 570

5.3.12 Freeze Damage

At subfreezing temperatures, water and aqueous solutionsin piping systems may freeze and cause failure because of theexpansion of these materials. After unexpectedly severefreezing weather, it is important to check for freeze damage toexposed piping components before the system thaws. If rup-ture has occurred, leakage may be temporarily prevented bythe frozen fluid. Low points, driplegs, and deadlegs of pipingsystems containing water should be carefully examined fordamage.

5.4 TYPES OF INSPECTION AND SURVEILLANCE

Different types of inspection and surveillance are appro-priate depending on the circumstances and the piping system(see note). These include the following:

a. Internal visual inspection.b. Thickness measurement inspection.c. External visual inspection.d. Vibrating piping inspection.e. Supplemental inspection.

Note: See Section 6 for frequency and extent of inspection.

5.4.1 Internal Visual Inspection

Internal visual inspections are not normally performed onpiping. When possible and practical, internal visual inspec-tions may be scheduled for systems such as large-diametertransfer lines, ducts, catalyst lines, or other large-diameterpiping systems. Such inspections are similar in nature to pres-sure vessel inspections and should be conducted with meth-ods and procedures similar to those outlined in API 510.Remote visual inspection techniques can be helpful wheninspecting piping too small to enter.

An additional opportunity for internal inspection is pro-vided when piping flanges are disconnected, allowing visualinspection of internal surfaces with or without the use ofNDE. Removing a section of piping and splitting it along itscenterline also permits access to internal surfaces where thereis need for such inspection.

5.4.2 Thickness Measurement Inspection

A thickness measurement inspection is performed to deter-mine the internal condition and remaining thickness of thepiping components. Thickness measurements may beobtained when the piping system is in or out of operation andshall be performed by the inspector or examiner.

5.4.3 External Visual Inspection

An external visual inspection is performed to determinethe condition of the outside of the piping, insulation system,painting and coating systems, and associated hardware; andto check for signs of misalignment, vibration, and leakage.When corrosion product buildup is noted at pipe support con-

tact areas, lifting off such supports may be required forinspection. When doing this, care should be exercised if thepiping is in-service.

External piping inspections may be made when the pipingsystem is in-service. Refer to API RP 574 for informationhelpful in conducting external inspections. A checklist toassist in conducting external piping inspections is provided inAppendix D.

External inspections shall include surveys for the condi-tion of piping hangers and supports. Instances of cracked orbroken hangers, “bottoming out” of spring supports, supportshoes displaced from support members, or other improperrestraint conditions shall be reported and corrected. Verticalsupport dummy legs also shall be checked to confirm thatthey have not filled with water that is causing external corro-sion of the pressure piping or internal corrosion of the supportleg. Horizontal support dummy legs also shall be checked todetermine that slight displacements from horizontal are notcausing moisture traps against the external surface of activepiping components.

Bellows expansion joints should be inspected visually forunusual deformations, misalignment, or displacements thatmay exceed design.

The inspector should examine the piping system for thepresence of any field modifications or temporary repairs notpreviously recorded on the piping drawings and/or records.The inspector also should be alert to the presence of any com-ponents in the service that may be unsuitable for long-termoperation, such as improper flanges, temporary repairs(clamps), modifications (flexible hoses), or valves ofimproper specification. Threaded components that may bemore easily removed and installed deserve particular atten-tion because of their higher potential for installation ofimproper components.

The periodic external inspection called for in 6.4 shouldnormally be conducted by the inspector, who also shall beresponsible for record keeping and repair inspection. Quali-fied operating or maintenance personnel also may conductexternal inspections, when acceptable to the inspector. Insuch cases, the persons conducting external piping inspec-tions in accordance with API 570 shall be qualified throughan appropriate amount of training.

In addition to these scheduled external inspections that aredocumented in inspection records, it is beneficial for personnelwho frequent the area to report deterioration or changes to theinspector. (See Appendix D and Section 6.3 of API RP 574 forexamples of such deterioration.)

5.4.4 Vibrating Piping and Line Movement Surveillance

Operating personnel should report vibrating or swayingpiping to engineering or inspection personnel for assessment.Other significant line movements should be reported that mayhave resulted from liquid hammer, liquid slugging in vapor



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

P

IPING

I

NSPECTION

C

ODE

—I

NSPECTION

, R

EPAIR

, A

LTERATION

,

AND

R

ERATING

OF

I

N

-S

ERVICE

P

IPING

S

YSTEMS

5-7

lines, or abnormal thermal expansion. At junctions wherevibrating piping systems are restrained, periodic magnetic-particle testing or liquid-penetrant testing should be consid-ered to check for the onset of fatigue cracking. Branch con-nections should receive special attention.

5.4.5 Supplemental Inspection

Other inspections may be scheduled as appropriate or nec-essary. Examples of such inspections include periodic use ofradiography and/or thermography to check for fouling orinternal plugging, thermography to check for hot spots inrefractory lined systems, or inspection for environmentalcracking. Acoustic emission, acoustic leak detection, andthermography can be used for remote leak detection and sur-veillance. Ultrasonics and/or radiography can be used fordetecting localized corrosion.

5.5 THICKNESS MEASUREMENT LOCATIONS

5.5.1 General

Thickness measurement locations (TMLs) are specificareas along the piping circuit where inspections are to bemade. The nature of the TML varies according to its locationin the piping system. The selection of TMLs shall considerthe potential for localized corrosion and service-specific cor-rosion as described in 5.3.

5.5.2 TML Monitoring

Each piping system shall be monitored by taking thick-ness measurements at TMLs. Piping circuits with highpotential consequences if failure should occur and thosesubject to higher corrosion rates or localized corrosionwill normally have more TMLs and be monitored morefrequently (see 6.3). TMLs should be distributed appropri-ately throughout each piping circuit. TMLs may be elimi-nated or the number reduced under certain circumstances,such as olefin plant cold side piping, anhydrous ammoniapiping, clean noncorrosive hydrocarbon product, or high-alloy piping for product purity. In circumstances whereTMLs will be substantially reduced or eliminated, personsknowledgeable in corrosion should be consulted.

The minimum thickness at each TML can be located byultrasonic scanning or radiography. Electromagnetic tech-niques also can be used to identify thin areas that may then bemeasured by ultrasonics or radiography. When accomplishedwith ultrasonics, scanning consists of taking several thicknessmeasurements at the TML searching for localized thinning.The thinnest reading or an average of several measurementreadings taken within the area of a test point shall be recordedand used to calculate corrosion rates, remaining life, and thenext inspection date in accordance with Section 7.

Where appropriate, thickness measurements shouldinclude measurements at each of the four quadrants on pipe

and fittings, with special attention to the inside and outsideradius of elbows and tees where corrosion/erosion couldincrease corrosion rates. As a minimum, the thinnest readingand its location shall be recorded.

TMLs should be established for areas with continuingCUI, corrosion at S/A interfaces, or other locations ofpotential localized corrosion as well as for general, uni-form corrosion.

TMLs should be marked on inspection drawings and onthe piping system to allow repetitive measurements at thesame TMLs. This recording procedure provides data for moreaccurate corrosion rate determination.

5.5.3 TML Selection

In selecting or adjusting the number and locations ofTMLs, the inspector should take into account the patterns ofcorrosion that would be expected and have been experiencedin the process unit. A number of corrosion processes commonto refining and petrochemical units are relatively uniform innature, resulting in a fairly constant rate of pipe wall reduc-tion independent of location within the piping circuit, eitheraxially or circumferentially. Examples of such corrosion phe-nomena include high-temperature sulfur corrosion and sourwater corrosion (provided velocities are not so excessive as tocause local corrosion/erosion of elbows, tees, and other simi-lar items). In these situations, the number of TMLs requiredto monitor a circuit will be fewer than those required to mon-itor circuits subject to more localized metal loss. In theory, acircuit subject to perfectly uniform corrosion could be ade-quately monitored with a single TML. In reality, corrosion isnever truly uniform, so additional TMLs may be required.Inspectors must use their knowledge (and that of others) ofthe process unit to optimize the TML selection for each cir-cuit, balancing the effort of collecting the data with the bene-fits provided by the data.

More TMLs should be selected for piping systems withany of the following characteristics:

a. Higher potential for creating a safety or environmentalemergency in the event of a leak.

b. Higher expected or experienced corrosion rates.

c. Higher potential for localized corrosion.

d. More complexity in terms of fittings, branches, deadlegs,injection points, and other similar items.

e. Higher potential for CUI.

Fewer TMLs can be selected for piping systems with anyof the following three characteristics:

a. Low potential for creating a safety or environmental emer-gency in the event of a leak.

b. Relatively noncorrosive piping systems.

c. Long, straight-run piping systems.



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

5-8 API 570

TMLs can be eliminated for piping systems with either ofthe following two characteristics:

a. Extremely low potential for creating a safety or environ-mental emergency in the event of a leak.b. Noncorrosive systems, as demonstrated by history or simi-lar service, and systems not subject to changes that couldcause corrosion.

5.6 THICKNESS MEASUREMENT METHODS

Ultrasonic thickness measuring instruments usually arethe most accurate means for obtaining thickness measure-ments on installed pipe larger than NPS 1. Radiographic pro-file techniques are preferred for pipe diameters of NPS 1 andsmaller. Radiographic profile techniques may be used forlocating areas to be measured, particularly in insulated sys-tems or where nonuniform or localized corrosion is sus-pected. Where practical, ultrasonics can then be used toobtain the actual thickness of the areas to be recorded. Fol-lowing ultrasonic readings at TMLs, proper repair of insula-tion and insulation weather coating is recommended toreduce the potential for CUI. Radiographic profile tech-niques, which do not require removing insulation, may beconsidered as an alternative.

When corrosion in a piping system is nonuniform or theremaining thickness is approaching the minimum requiredthickness, additional thickness measuring may be required.Radiography or ultrasonic scanning are the preferred methodsin such cases. Eddy current devices also may be used.

When ultrasonic measurements are taken above 150°F(65°C), instruments, couplants, and procedures should beused that will result in accurate measurements at the highertemperatures. Measurements should be adjusted by theappropriate temperature correction factor.

Inspectors should be aware of possible sources of mea-surement inaccuracies and make every effort to eliminatetheir occurrence. As a general rule, each of the NDE tech-niques will have practical limits with respect to accuracy.Factors that can contribute to reduced accuracy of ultrasonicmeasurements include the following:

a. Improper instrument calibration.b. External coatings or scale.c. Excessive surface roughness.d. Excessive “rocking” of the probe (on the curved surface).e. Subsurface material flaws, such as laminations.f. Temperature effects [at temperatures above 150°F (65°C)].g. Small flaw detector screens.h. Thicknesses of less than

1

/

8

inch (3.2 mm) for typical digi-tal thickness gauges.

In addition, it must be kept in mind that the pattern of cor-rosion can be nonuniform. For corrosion rate determinationsto be valid, it is important that measurements on the thinnestpoint be repeated as closely as possible to the same location.

Alternatively, the minimum reading or an average of severalreadings at a test point may be considered.

When piping systems are out of service, thickness mea-surements may be taken through openings using calipers.Calipers are useful in determining approximate thicknesses ofcastings, forgings, and valve bodies, as well as pit depthapproximations from CUI on pipe.

Pit depth measuring devices also may be used to deter-mine the depth of localized metal loss.

5.7 PRESSURE TESTING OF PIPING SYSTEMS

Pressure tests are not normally conducted as part of a rou-tine inspection. (See 8.2.6 for pressure testing requirementsfor repairs, alterations, and rerating.) Exceptions to thisinclude requirements of the United States Coast Guard foroverwater piping and requirements of local jurisdictions, afterwelded alterations or when specified by the inspector or pip-ing engineer. When they are conducted, pressure tests shall beperformed in accordance with the requirements of ASMEB31.3. Additional considerations are provided in API RP 574and API RP 579. Lower pressure tests, which are used onlyfor tightness of piping systems, may be conducted at pres-sures designated by the owner/user.

The test fluid should be water unless there is the possibilityof damage due to freezing or other adverse effects of water onthe piping system or the process or unless the test water willbecome contaminated and its disposal will present environ-mental problems. In either case, another suitable nontoxic liq-uid may be used. If the liquid is flammable, its flash point shallbe at least 120°F (49°C) or greater, and consideration shall begiven to the effect of the test environment on the test fluid.

Piping fabricated of or having components of 300 seriesstainless steel should be hydrotested with a solution made upof potable water (see note) or steam condensate. After testingis completed, the piping should be thoroughly drained (allhigh-point vents should be open during draining), air blown,or otherwise dried. If potable water is not available or ifimmediate draining and drying is not possible, water having avery low chloride level, higher pH (>10), and inhibitor addi-tion may be considered to reduce the risk of pitting andmicrobiologically induced corrosion.

Note: Potable water in this context follows U.S. practice, with 250parts per million maximum chloride, sanitized with chlorine orozone.

For sensitized austenitic stainless steel piping subject topolythionic stress corrosion cracking, consideration should begiven to using an alkaline-water solution for pressure testing(see NACE RP0170).

If a pressure test is to be maintained for a period of timeand the test fluid in the system is subject to thermal expan-sion, precautions shall be taken to avoid excessive pressure.

When a pressure test is required, it shall be conducted afterany heat treatment.

01



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

P

IPING

I

NSPECTION

C

ODE

—I

NSPECTION

, R

EPAIR

, A

LTERATION

,

AND

R

ERATING

OF

I

N

-S

ERVICE

P

IPING

S

YSTEMS

5-9

Before applying a hydrostatic test to piping systems, con-sideration should be given to the supporting structure design.

A pneumatic pressure test may be used when it is impracti-cable to hydrostatically test due to temperature, structural, orprocess limitations. However, the potential risks to personneland property of pneumatic testing shall be considered whencarrying out such a test. As a minimum, the inspection pre-cautions contained in ASME B31.3 shall be applied in anypneumatic testing.

During a pressure test, where the test pressure will exceedthe set pressure of the safety valve on a piping system, thesafety relief valve or valves should be removed or blanked forthe duration of the test. As an alternative, each valve diskmust be held down by a suitably designed test clamp. Theapplication of an additional load to the valve spring by turn-ing the adjusting screw is not recommended. Other appurte-nances that are incapable of withstanding the test pressure,such as gage glasses, pressure gages, expansion joints, andrupture disks, should be removed or blanked. Lines contain-ing expansion joints that cannot be removed or isolated maybe tested at a reduced pressure in accordance with the princi-ples of ASME B31.3. If block valves are used to isolate a pip-ing system for a pressure test, caution should be used to notexceed the permissible seat pressure as described in ASMEB16.34 or applicable valve manufacturer data.

Upon completion of the pressure test, pressure reliefdevices of the proper settings and other appurtenancesremoved or made inoperable during the pressure test shall bereinstalled or reactivated.

5.8 MATERIAL VERIFICATION AND TRACEABILITY

During repairs or alterations alloy material piping systems,WHERE THE ALLOY MATERIAL IS REQUIRED TOMAINTAIN PRESSURE CONTAINMENT, the inspectorshall verify that the installation of new materials is consistentwith the selected or specified construction materials. Thismaterial verification program should be consistent with APIRP 578. Using risk assessment procedures, the owner/user canmake this assessment by 100-percent verification, PMI testingin certain critical situations, or by sampling a percentage of thematerials. PMI testing can be accomplished by the inspectoror the examiner with the use of suitable methods as describedin API RP 578.

If a piping system component should fail because anincorrect material was inadvertently substituted for the properpiping material, the inspector shall consider the need for fur-ther verification of existing piping materials. The extent offurther verification will depend upon circumstances such asthe consequences of failure and the likelihood of furthermaterial errors.

The owner/user shall assess the need and extent regardingapplication of the practices consistent with API RP 578addressing inadvertent material substitution in existing alloy

piping systems. A material verification program consistentwith API RP 578 may include procedures for prioritizationand risk ranking piping circuits. That assessment may lead toretroactive PMI testing, as described in API RP 578, to con-firm that the installed materials are consistent with theintended service. Components identified during this verifica-tion that do not meet acceptance criteria of the PMI testingprogram (such as in API RP 578, Section 6) would be tar-geted for replacement. The owner/user and authorized pipinginspector, in consultation with a corrosion specialist, shallestablish a schedule for replacement of those components.The authorized inspector shall use periodic NDE, as neces-sary, on the identified components until the replacement.

5.9 INSPECTION OF VALVES

Normally, thickness measurements are not routinely takenon valves in piping circuits. The body of a valve is normallythicker than other piping components for design reasons.However, when valves are dismantled for servicing andrepair, the shop should be attentive to any unusual corrosionpatterns or thinning and, when noted, report that informationto the inspector. Bodies of valves that are exposed to steeptemperature cycling (for example, catalytic reforming unitregeneration and steam cleaning) should be examined period-ically for thermal fatigue cracking.

If gate valves are known to be or are suspected of beingexposed to corrosion/erosion, thickness readings should betaken between the seats, since this is an area of high turbu-lence and high stress.

Control valves or other throttling valves, particularly inhigh-pressure drop-and-slurry services, can be susceptible tolocalized corrosion/erosion of the body downstream of theorifice. If such metal loss is suspected, the valve should beremoved from the line for internal inspection. The inside ofthe downstream mating flange and piping also should beinspected for local metal loss.

When valve body and/or closure pressure tests are per-formed after servicing, they should be conducted in accor-dance with API Std 598.

Critical check valves should be visually and internallyinspected to ensure that they will stop flow reversals. Anexample of a critical check valve may be the check valvelocated on the outlet of a multistage, high head hydroprocess-ing charge pump. Failure of such a check valve to operatecorrectly could result in overpressuring the piping during aflow reversal. The normal visual inspection method shouldinclude:

a. Checking to insure that the flapper is free to move, asrequired, without excessive looseness from wear.b. The flapper stop should not have excessive wear. This willminimize the likelihood that the flapper will move past thetop dead central position and remain in an open positionwhen the check valve is mounted in a vertical position.

00

00

00



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

5-10 API 570

c. The flapper nut should be secured to the flapper bolt toavoid backing off in service.

Leak checks of critical check valves are normally notrequired.

5.10 INSPECTION OF WELDS IN-SERVICE

Inspection for piping weld quality is normally accom-plished as a part of the requirements for new construction,repairs, or alterations. However, welds are often inspected forcorrosion as part of a radiographic profile inspection or aspart of internal inspection. When preferential weld corrosionis noted, additional welds in the same circuit or system shouldbe examined for corrosion.

On occasion, radiographic profile examinations mayreveal what appears to be imperfections in the weld. If crack-like imperfections are detected while the piping system is inoperation, further inspection with weld quality radiographyand/or ultrasonics may be used to assess the magnitude of theimperfection. Additionally, an effort should be made to deter-mine whether the crack-like imperfections are from originalweld fabrication or may be from an environmental crackingmechanism.

Environmental cracking shall be assessed by the pipingengineer.

If the noted imperfections are a result of original weld fab-rication, inspection and/or engineering analysis is required toassess the impact of the weld quality on piping integrity. Thisanalysis may be one or more of the following:

a. Inspector judgment.b. Certified welding inspector judgment.c. Piping engineer judgment.d. Engineering fitness-for-service analysis.

Issues to consider when assessing the quality of existingwelds include the following:

a. Original fabrication inspection acceptance criteria.b. Extent, magnitude, and orientation of imperfections.c. Length of time in-service.d. Operating versus design conditions.e. Presence of secondary piping stresses (residual andthermal).f. Potential for fatigue loads (mechanical and thermal).g. Primary or secondary piping system.h. Potential for impact or transient loads.i. Potential for environmental cracking.j. Weld hardness.

In many cases for in-service welds, it is not appropriate touse the random or spot radiography acceptance criteria forweld quality in ASME B31.3. These acceptance criteria areintended to apply to new construction on a sampling of welds,

not just the welds examined, in order to assess the probablequality of all welds (or welders) in the system. Some weldsmay exist that will not meet these criteria but will still performsatisfactorily in-service after being hydrotested. This is espe-cially true on small branch connections that are normally notexamined during new construction.

The owner/user shall specify industry-qualified UT shearwave examiners when the owner/user requires the following:a) detection of interior surface (ID) breaking planar flawswhen inspecting from the external surface (OD); or b) wheredetection, characterization, and/or through-wall sizing isrequired of planar defects. Application examples for the use ofsuch industry-qualified UT shear wave examiners include fit-ness-for-service and monitoring of known flaws. The require-ment for use of industry-qualified UT shear wave examinersbecomes effective two years after publication in this code oraddendum.

5.11 INSPECTION OF FLANGED JOINTS

The markings on a representative sample of newlyinstalled fasteners and gaskets should be examined todetermine whether they meet the material specification.The markings are identified in the applicable ASME andASTM standards. Questionable fasteners should be veri-fied or renewed.

Fasteners should extend completely through their nuts.Any fastener failing to do so is considered acceptablyengaged if the lack of complete engagement is not more thanone thread.

If installed flanges are excessively bent, their markingsand thicknesses should be checked against engineeringrequirements before taking corrective action.

Flange and valve bonnet fasteners should be examinedvisually for corrosion.

Flanged and valve bonnet joints should be examined forevidence of leakage, such as stains, deposits, or drips. Processleaks onto flange and bonnet fasteners may result in corrosionor environmental cracking. This examination should includethose flanges enclosed with flange or splash-and-spray guards.

Flanged joints that have been clamped and pumped withsealant should be checked for leakage at the bolts. Fastenerssubjected to such leakage may corrode or crack (causticcracking, for example). If repumping is contemplated,affected fasteners should be renewed first.

Fasteners on instrumentation that are subject to processpressure and/or temperature should be included in the scopeof these examinations.

See API RP 574 for recommended practices when flangedjoints are opened.

01



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

6-1

SECTION 6—FREQUENCY AND EXTENT OF INSPECTION

6.1 GENERAL

The frequency and extent of inspection on piping circuitsdepend on the forms of degradation that can affect the pipingand consequence of a piping failure. The various forms ofdegradation that can affect refinery piping circuits aredescribed in 5.3, while a simplified classification of pipingbased on the consequence of failure is defined in 6.2. Asdescribed in 5.1, inspection strategy based on likelihood andconsequence of failure, is referred to as risk-based inspection.

The simplified piping classification scheme in Section 6.2is based on the consequence of a failure. The classification isused to establish frequency and extent of inspection. Theowner/user may devise a more extensive classificationscheme that more accurately assesses consequence for certainpiping circuits. The consequence assessment would considerthe potential for explosion, fire, toxicity, environmentalimpact, and other potential effects associated with a failure.

After an effective assessment is conducted, the results canbe used to establish a piping circuit inspection strategy andmore specifically better define the following:

a. The most appropriate inspection methods, scope, tools andtechniques to be utilized based on the expected forms ofdegradation;

b. The appropriate inspection frequency;

c. The need for pressure testing after damage has beenincurred or after repairs or modifications have been com-pleted; and

d. The prevention and mitigation steps to reduce the likeli-hood and consequence of a piping failure.

A RBI assessment may be used to increase or decrease theinspection limits described in Table 6-1. Similarly, the extentof inspection may be increased or decreased beyond the tar-gets in Table 6-2, by a RBI assessment. When used toincrease inspection interval limits or the extent of inspection,RBI assessments shall be conducted at intervals not to exceedthe respective limits in Table 6-1, or more often if warrantedby process, equipment, or consequence changes. These RBIassessments shall be reviewed and approved by a piping engi-neer and authorized piping inspector at intervals not to exceedthe respective limits in Table 6-1, or more often if warrantedby process, equipment, or consequence changes.

6.2 PIPING SERVICE CLASSES

All process piping systems shall be categorized into differ-ent classes. Such a classification system allows extra inspec-tion efforts to be focused on piping systems that may have thehighest potential consequences if failure or loss of contain-ment should occur. In general, the higher classified systems

require more extensive inspection at shorter intervals in orderto affirm their integrity for continued safe operation. Classifi-cations should be based on potential safety and environmentaleffects should a leak occur.

Owner/users shall maintain a record of process piping flu-ids handled, including their classifications. API RP 750 andNFPA 704 provide information that may be helpful in classi-fying piping systems according to the potential hazards of theprocess fluids they contain.

The three classes listed below in 6.2.1 through 6.2.3 arerecommended.

6.2.1 Class 1

Services with the highest potential of resulting in animmediate emergency if a leak were to occur are in Class 1.Such an emergency may be safety or environmental in nature.Examples of Class 1 piping include, but are not necessarilylimited to, those containing the following:

a. Flammable services that may auto-refrigerate and lead tobrittle fracture.

b. Pressurized services that may rapidly vaporize duringrelease, creating vapors that may collect and form an explo-sive mixture, such as C2, C3, and C4 streams. Fluids that willrapidly vaporize are those with atmospheric boiling tempera-tures below 50°F (10°C).

c. Hydrogen sulfide (greater than 3 percent weight) in a gas-eous stream.

d. Anhydrous hydrogen chloride.

e. Hydrofluoric acid.

f. Piping over or adjacent to water and piping over publicthroughways. (Refer to Department of Transportation andU.S. Coast Guard regulations for inspection of overwaterpiping.)

6.2.2 Class 2

Services not included in other classes are in Class 2. Thisclassification includes the majority of unit process piping andselected off-site piping. Typical examples of these servicesinclude those containing the following:

a. On-site hydrocarbons that will slowly vaporize duringrelease such as those operating below the flash point.

b. Hydrogen, fuel gas, and natural gas.

c. On-site strong acids and caustics.

6.2.3 Class 3

Services that are flammable but do not significantly vapor-ize when they leak and are not located in high-activity areasare in Class 3. Services that are potentially harmful to human

03

03



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

6-2 API 570

tissue but are located in remote areas may be included in thisclass. Examples of Class 3 service are as follows:

a. On-site hydrocarbons that will not significantly vaporizeduring release such as those operating below the flash point.b. Distillate and product lines to and from storage andloading.c. Off-site acids and caustics.

6.3 INSPECTION INTERVALS

The interval between piping inspections shall be estab-lished and maintained using the following criteria:

a. Corrosion rate and remaining life calculations.b. Piping service classification.c. Applicable jurisdictional requirements.d. Judgment of the inspector, the piping engineer, the pipingengineer supervisor, or a corrosion specialist, based on oper-ating conditions, previous inspection history, currentinspection results, and conditions that may warrant supple-mental inspections covered in 5.4.5.

The owner/user or the inspector shall establish inspectionintervals for thickness measurements and external visualinspections and, where applicable, for internal and supple-mental inspections.

Thickness measurements should be scheduled based on thecalculation of not more than half the remaining life deter-mined from corrosion rates indicated in 7.1.1 or at the maxi-mum intervals suggested in Table 6-1, whichever is shorter.Shorter intervals may be appropriate under certain circum-stances. Prior to using Table 6-1, corrosion rates should becalculated in accordance with 7.1.3.

Table 6-1 contains recommended maximum inspectionintervals for the three categories of piping services describedin 6.2, as well as recommended intervals for injection pointsand S/A interfaces.

The inspection interval must be reviewed and adjustedas necessary after each inspection or significant change inoperating conditions. General corrosion, localized corro-sion, pitting, environmental cracking, and other forms ofdeterioration must be considered when establishing thevarious inspection intervals.

6.4 EXTENT OF VISUAL EXTERNAL AND CUI INSPECTIONS

External visual inspections, including inspections for corro-sion under insulation (CUI), should be conducted at maximumintervals listed in Table 6-1 to evaluate items such as those inAppendix D. Alternatively, external visual inspection intervalscan be established by using a valid RBI assessment conductedin accordance with API RP 580. The external visual inspectionon bare piping is to assess the condition of paint and coatingsystems, to check for external corrosion, and to check for

other forms of deterioration. This external visual inspectionfor potential CUI is also to assess insulation condition andshall be conducted on all piping systems susceptible to CUIlisted in 5.3.3.1. The results of the visual inspection should bedocumented to facilitate follow-up inspections.

Following the external visual inspection of susceptible sys-tems, additional examination is required for the inspection ofCUI. The extent and type of the additional CUI inspection arelisted in Table 6-2. Damaged insulation at higher elevationsmay result in CUI in lower areas remote from the damage.NDE inspection for CUI should also be conducted as listed inTable 6-2 at suspect locations of 5.3.3.2 (excluding c) meetingthe temperature criteria for 5.3.3.1 (e, f, h). Radiographicexamination or insulation removal and visual inspection isnormally required for this inspection at damaged or suspectlocations. Other NDE assessment methods may be used whereapplicable. If the inspection of the damaged or suspect areashas located significant CUI, additional areas should beinspected and, where warranted, up to 100 percent of the cir-cuit should be inspected.

The extent of the CUI program described in Table 6-2should be considered as target levels for piping systems andlocations with no CUI inspection experience. It is recognizedthat several factors may affect the likelihood of CUI to include:

a. Local climatic conditions (see 5.3.3).

b. Insulation design.

c. Coating quality.

d. Service conditions.

Facilities with CUI inspection experience may increase orreduce the CUI inspection targets of Table 6-2. An exactaccounting of the CUI inspection targets is not required. Theowner/user may confirm inspection targets with operationalhistory or other documentation.

Piping systems that are known to have a remaining lifeof over 10 years or that are adequately protected againstexternal corrosion need not be included for the NDEinspection recommended in Table 6-2. However, the con-dition of the insulating system or the outer jacketing, suchas a cold-box shell, should be observed periodically byoperating or other personnel. If deterioration is noted, itshould be reported to the inspector. The following areexamples of these systems:

a. Piping systems insulated effectively to preclude theentrance of moisture.

b. Jacketed cryogenic piping systems.

c. Piping systems installed in a cold box in which the atmo-sphere is purged with an inert gas.

d. Piping systems in which the temperature being maintainedis sufficiently low or sufficiently high to preclude the pres-ence of water.

03

03

03



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

P

IPING

I

NSPECTION

C

ODE

—I

NSPECTION

, R

EPAIR

, A

LTERATION

,

AND

R

ERATING

OF

I

N

-S

ERVICE

P

IPING

S

YSTEMS

6-3

6.5 EXTENT OF THICKNESS MEASUREMENT INSPECTION

To satisfy inspection interval requirements, each thicknessmeasurement inspection should obtain thickness readings ona representative sampling of TMLs on each circuit (see 5.5).This representative sampling should include data for all thevarious types of components and orientations (horizontal andvertical) found in each circuit. This sampling also mustinclude TMLs with the earliest renewal date as of the previ-ous inspection. The more TMLs measured for each circuit,the more accurately the next inspection date will be projected.Therefore, scheduled inspection of circuits should obtain asmany measurements as necessary.

The extent of inspection for injection points is coveredin 5.3.1.

6.6 EXTENT OF SMALL-BORE, AUXILIARY PIPING, AND THREADED-CONNECTIONS INSPECTIONS

6.6.1 Small-Bore Piping Inspection

Small-bore piping (SBP) that is primary process pipingshould be inspected in accordance with all the requirementsof this document.

SBP that is secondary process piping has different mini-mum requirements depending upon service classification.Class 1 secondary SBP shall be inspected to the same require-ments as primary process piping. Inspection of Class 2 andClass 3 secondary SBP is optional. SBP deadlegs (such as levelbridles) in Class 2 and Class 3 systems should be inspectedwhere corrosion has been experienced or is anticipated.

6.6.2 Auxiliary Piping Inspection

Inspection of secondary, auxiliary SBP associated withinstruments and machinery is optional. Criteria to consider indetermining whether auxiliary SBP will need some form ofinspection include the following:

a. Classification.b. Potential for environmental or fatigue cracking.c. Potential for corrosion based on experience with adjacentprimary systems.d. Potential for CUI.

6.6.3 Threaded-Connections Inspection

Inspection of threaded connections will be according to therequirements listed above for small-bore and auxiliary piping.

When selecting TMLs on threaded connections, include onlythose that can be radiographed during scheduled inspections.

Threaded connections associated with machinery and sub-ject to fatigue damage should be periodically assessed and con-sidered for possible renewal with a thicker wall or upgrading towelded components. The schedule for such renewal willdepend on several issues, including the following:

a. Classification of piping.

b. Magnitude and frequency of vibration.

c. Amount of unsupported weight.

d. Current piping wall thickness.

e. Whether or not the system can be maintained on-stream.

f. Corrosion rate.

g. Intermittent service.

Note: Thickness measurements apply to systems for which TMLshave been established in accordance with 5.5.

a

See 5.3.1. Inspection intervals for potentially corrosive injection/mix points can also be established by a valid risk-based inspectionanalysis in accordance with API RP 580.

b

See 5.3.4.

Table 6-1—Recommended Maximum Inspection Intervals

Type of Circuit ThicknessMeasurements

VisualExternal

Class 1 5 years 5 yearsClass 2 10 years 5 yearsClass 3 10 years 10 yearsInjection points

a

3 years By ClassSoil-to-air interfaces

b

– By Class

Table 6-2—Recommended Extent of CUI InspectionFollowing Visual Inspection

Approximate Amount of Follow-up Examination with NDE or

Insulation Removal at Areas with Damaged Insulation

Approximate Amount of CUI Inspection by NDE at Suspect

Areas (5.3.3.2) on Piping Systems within Susceptible Temperature

Ranges (5.3.3.2,e,f,h)

Pipe Class1 75% 50%2 50% 33%3 25% 10%

03



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

7-1

SECTION 7—INSPECTION DATA EVALUATION, ANALYSIS, AND RECORDING

7.1 CORROSION RATE DETERMINATION

7.1.1 Remaining Life Calculations

The remaining life of the piping system shall be calculatedfrom the following formula:

where

t

actual

= the actual thickness, in inches (millimeters), measured at the time of inspection for a given location or component as specified in 5.6.,

t

required

= the required thickness, in inches (millimeters), at the same location or component as the

t

actual

measurement computed by the design formulas (e.g., pressure and structural) before corrosion allowance and manufacturer’s tolerance are added.

The long-term (LT) corrosion rate of piping circuits shallbe calculated from the following formula:

The short term (ST) corrosion rate of piping circuits shallbe calculated from the following formula:

where

t

initial

= the thickness, in inches (millimeters), at the same location as t

actual

measured at initial installation or at the commencement of a new corrosion rate environment,

t

previous

= the thickness, in inches (millimeters), at the same location as t

actual

measured during one or more previous inspections.

The preceding formulas may be applied in a statisticalapproach to assess corrosion rates and remaining life calcula-tions for the piping system. Care must be taken to ensure that

the statistical treatment of data results reflects the actual con-dition of the various pipe components. Statistical analysisemploying point measurements is not applicable to pipingsystems with significant localized unpredictable corrosionmechanisms.

Long-term and short-term corrosion rates should be com-pared to see which results in the shortest remaining life aspart of the data assessment. The authorized inspector, in con-sultation with a corrosion specialist, shall select the corrosionrate that best reflects the current process. (See 6.3 for inspec-tion interval determination.)

7.1.2 Newly Installed Piping Systems or Changes in Service

For new piping systems and piping systems for which ser-vice conditions are being changed, one of the following meth-ods shall be employed to determine the probable rate ofcorrosion from which the remaining wall thickness at thetime of the next inspection can be estimated:

a. A corrosion rate for a piping circuit may be calculatedfrom data collected by the owner/user on piping systems ofsimilar material in comparable service.b. If data for the same or similar service are not available, acorrosion rate for a piping circuit may be estimated from theowner/user’s experience or from published data on pipingsystems in comparable service.c. If the probable corrosion rate cannot be determined byeither method listed in item a or item b, the initial thicknessmeasurement determinations shall be made after no morethan 3 months of service by using nondestructive thicknessmeasurements of the piping system. Corrosion monitoringdevices, such as corrosion coupons or corrosion probes,may be useful in establishing the timing of these thicknessmeasurements. Subsequent measurements shall be madeafter appropriate intervals until the corrosion rate isestablished.

7.1.3 Existing Piping Systems

Corrosion rates shall be calculated on either a short-termor a long-term basis.

If calculations indicate that an inaccurate rate of corrosionhas been assumed, the rate to be used for the next period shallbe adjusted to agree with the actual rate found.

7.2 MAXIMUM ALLOWABLE WORKING PRESSURE DETERMINATION

The maximum allowable working pressure (MAWP) forthe continued use of piping systems shall be established usingthe applicable code. Computations may be made for known

Remaining Life (years)tactual trequired–corrosion rate

inches (mm) per year[ ]

-------------------------------------------------------=

01

Corrosion rate (LT)tinitial tactual–

time (years) between tinitial and tactual

---------------------------------------------------=

Corrosion rate (ST)tprevious tactual–

time (years) between tprevious and tactual

---------------------------------------------------=

01

01



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

7-2 API 570

materials if all the following essential details are known tocomply with the principles of the applicable code:

a. Upper and/or lower temperature limits for specificmaterials.

b. Quality of materials and workmanship.

c. Inspection requirements.

d. Reinforcement of openings.

e. Any cyclical service requirements.

For unknown materials, computations may be madeassuming the lowest grade material and joint efficiency in theapplicable code. When the MAWP is recalculated, the wallthickness used in these computations shall be the actual thick-ness as determined by inspection (see 5.6 for definition)minus twice the estimated corrosion loss before the date ofthe next inspection (see 6.3). Allowance shall be made for theother loadings in accordance with the applicable code. Theapplicable code allowances for pressure and temperature vari-ations from the MAWP are permitted provided all of the asso-ciated code criteria are satisfied.

Table 7-1 contains two examples of calculations of MAWPillustrating the use of the corrosion half-life concept.

7.3 RETIREMENT THICKNESS DETERMINATION

The minimum required pipe wall retirement thickness shallbe equal to or greater than the minimum required thickness, orretirement thickness, and shall be based on pressure, mechan-ical, and structural considerations using the appropriatedesign formulae and code allowable stress. Consideration ofboth general and localized corrosion shall be included. Forservices with high potential consequences if failure were tooccur, the piping engineer should consider increasing therequired minimum thickness above the calculated minimumthickness to provide for unanticipated or unknown loadings,undiscovered metal loss, or resistance to normal abuse. In thiscase, the retirement thickness shall be used in lieu of the min-imum required thickness in 7.1.1 for remaining life calcula-tions.

7.4 ASSESSMENT OF INSPECTION FINDINGS

Pressure containing components found to have degrada-tion that could affect their load carrying capability (pres-sure loads and other applicable loads, e.g., weight, wind,etc., per API RP 579) shall be evaluated for continued ser-vice. Fitness-for-service techniques, such as those docu-mented in API RP 579, may be used for this evaluation.The fitness-for-service techniques used must be applicableto the specific degradation observed. The following tech-niques may be used as applicable:

a. To evaluate metal loss in excess of the corrosion allow-ance, a fitness-for-service assessment may be performed inaccordance with one of the following sections of API RP 579.

This assessment requires the use of a future corrosion allow-ance, which shall be established, based on Section 7.1 of thisinspection code.

1. Assessment of General Metal Loss—API RP 579,Section 4.

2. Assessment of Local Metal Loss—API RP 579, Sec-tion 5.

3. Assessment of Pitting Corrosion—API RP 579, Sec-tion 6.

b. To evaluate blisters and laminations, a fitness-for-serviceassessment should be performed in accordance with API RP579, Section 7. In some cases, this evaluation will require theuse of a future corrosion allowance, which shall be estab-lished, based on Section 7.1 of this inspection code.

c. To evaluate weld misalignment and shell distortions, a fit-ness for service assessment should be performed inaccordance with API RP 579, Section 8.

d. To evaluate crack-like flaws, a fitness for service assess-ment should be performed in accordance with API RP 579,Section 9.

e. To evaluate the effects of fire damage, a fitness for serviceassessment should be performed in accordance with API RP579, Section 11.

7.5 PIPING STRESS ANALYSIS

Piping must be supported and guided so that (a) its weightis carried safely, (b) it has sufficient flexibility for thermalexpansion or contraction, and (c) it does not vibrate exces-sively. Piping flexibility is of increasing concern the larger thediameter of the piping and the greater the difference betweenambient and operating temperature conditions.

Piping stress analysis to assess system flexibility and sup-port adequacy is not normally performed as part of a pipinginspection. However, many existing piping systems were ana-lyzed as part of their original design or as part of a rerating ormodification, and the results of these analyses can be usefulin developing inspection plans. When unexpected movementof a piping system is observed, such as during an externalvisual inspection (see 5.4.3), the inspector should discussthese observations with the piping engineer and evaluate theneed for conducting a piping stress analysis.

Piping stress analysis can identify the most highly stressedcomponents in a piping system and predict the thermal move-ment of the system when it is placed in operation. This infor-mation can be used to concentrate inspection efforts at thelocations most prone to fatigue damage from thermal expan-sion (heat-up and cool-down) cycles and/or creep damage inhigh-temperature piping. Comparing predicted thermal move-ments with observed movements can help identify the occur-rence of unexpected operating conditions and deterioration ofguides and supports. Consultation with the piping engineer

01

01



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

P

IPING

I

NSPECTION

C

ODE

—I

NSPECTION

, R

EPAIR

, A

LTERATION

,

AND

R

ERATING

OF

I

N

-S

ERVICE

P

IPING

S

YSTEMS

7-3

Table 7-1—Two Examples of the Calculation of Maximum Allowable Working Pressure (MAWP) Illustrating the Use of the Corrosion Half-Life Concept

Example 1:

Design pressure/temperature 500 psig/400°F (3447 kPA/204°C)

Pipe description NPS 16, standard weight, A 106-B

Outside diameter of pipe, D 16 in. (406 mm)

Allowable stress 20,000 psi (137,900 kPa)

Longitudinal weld efficiency, E

1.0

Thickness determined from inspection 0.32 in. (8.13 mm)

Observed corrosion rate (see 7.1.1)

0.01 in./yr. (0.254 mm/yr.)

Next planned inspection 5 yrs.

Estimated corrosion loss by date of next inspection = 5

X

0.01 = 0.05 in. (5

X

0.254 = 1.27mm)

MAWP

In U.S. units

= 2SE

t

/D

= 550 psig

In S.I units

= 3747 kPa

Conclusion: OK

Example 2:

Next planned inspection 7 yrs.

Estimated corrosion loss by date of next inspection = 7

X

0.01 = 0.07 in. (7

x

0.254 = 1.78mm)

MAWP

In U.S. units

= 2SE

t

/D

= 450 psig

In S.I units = 3104 kPa

Conclusion: Must reduce inspection interval or determine that normal operating pressure will not exceed this new MAWPduring the seventh year, or renew the piping before the seventh year.

Notes: 1. psig = pounds per square inch gauge; psi = pounds per square inch.2. The formula for MAWP is from ASME B31.3, Equation 3b, where

t

= corroded thickness.

2 20,000( )× 1.0( )× 0.32(× 2 0.05×( ) )–16

----------------------------------------------------------------------------------------------------

2 137,900( )× 1.0 )(× 8.13( ) 2 1.27×( )–( )×406

------------------------------------------------------------------------------------------------------------

2 20,000( )× 1.0( )× 0.32( 2 0.07×( )–× )16

----------------------------------------------------------------------------------------------------

2 137,900( )× 1.0 )(× 8.13 2 1.78×( )–( )×406

------------------------------------------------------------------------------------------------------- 01



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

7-4 API 570

may be necessary to explain observed deviations from theanalysis predictions, particularly for complicated systemsinvolving multiple supports and guides between end points.

Piping stress analysis also can be employed to help solveobserved piping vibration problems. The natural frequenciesin which a piping system will vibrate can be predicted byanalysis. The effects of additional guiding can be evaluated toassess its ability to control vibration by increasing the sys-tem’s natural frequencies beyond the frequency of excitingforces, such as machine rotational speed. It is important todetermine that guides added to control vibration do notadversely restrict thermal expansion.

7.6 REPORTING AND RECORDS FOR PIPING SYSTEM INSPECTION

Any significant increase in corrosion rates shall bereported to the owner/user for appropriate action.

The owner/user shall maintain appropriate permanentand progressive records of each piping system covered byAPI 570. These records shall contain pertinent data such aspiping system service; classification; identification num-bers; inspection intervals; and documents necessary torecord the name of the individual performing the testing,the date, the types of testing, the results of thickness mea-surements and other tests, inspections, repairs (temporaryand permanent), alterations, or rerating. Design informa-tion and piping drawings may be included. Information on

maintenance activities and events affecting piping systemintegrity also should be included. The date and results ofrequired external inspections shall be recorded. (See APIRP 574 for guidance on piping inspection records.)

The use of a computer-based system for storing, calculat-ing, and analyzing data should be considered in view of thevolume of data that will be generated as part of a piping test-point program. Computer programs are particularly useful forthe following:

a. Storing the actual thickness readings.b. Calculating short- and long-term corrosion rates, retire-ment dates, MAWP, and reinspection intervals on a test-pointby test-point basis.c. Highlighting areas of high corrosion rates, circuits over-due for inspection, circuits close to retirement thickness, andother information.d. Fitness-for-service assessment documentation require-ments are described in API RP 579, Section 2.8. Specificdocumentation requirements for the type of flaw beingassessed are provided in the appropriate section of API RP579.

Algorithms for the analysis of data from entire circuitsalso may be included in the program. Care should be taken toensure that the statistical treatment of circuit data results inpredictions that accurately reflect the actual condition of thepiping circuit.

01



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

8-1

SECTION 8—REPAIRS, ALTERATIONS, AND RERATING OF PIPING SYSTEMS

8.1 REPAIRS AND ALTERATIONS

The principles of ASME B31.3 or the code to which thepiping system was built shall be followed.

8.1.1 Authorization

All repair and alteration work must be done by a repairorganization as defined in Section 3 and must be authorizedby the inspector prior to its commencement. Authorization foralteration work to a piping system may not be given withoutprior consultation with, and approval by, the piping engineer.The inspector will designate any inspection hold pointsrequired during the repair or alteration sequence. The inspec-tor may give prior general authorization for limited or routinerepairs and procedures, provided the inspector is satisfiedwith the competency of the repair organization.

8.1.2 Approval

All proposed methods of design, execution, materials,welding procedures, examination, and testing must beapproved by the inspector or by the piping engineer, as appro-priate. Owner/user approval of on-stream welding is required.

Welding repairs of cracks that occurred in-service shouldnot be attempted without prior consultation with the pipingengineer in order to identify and correct the cause of thecracking. Examples are cracks suspected of being caused byvibration, thermal cycling, thermal expansion problems, andenvironmental cracking.

The inspector shall approve all repair and alteration workat designated hold points and after the repairs and alterationshave been satisfactorily completed in accordance with therequirements of API 570.

8.1.3 Welding Repairs (Including On-Stream)

8.1.3.1 Temporary Repairs

For temporary repairs, including on-stream, a full encir-clement welded split sleeve or box-type enclosure designedby the piping engineer may be applied over the damaged orcorroded area. Longitudinal cracks shall not be repaired inthis manner unless the piping engineer has determined thatcracks would not be expected to propagate from under thesleeve. In some cases, the piping engineer will need to consultwith a fracture analyst.

If the repair area is localized (for example, pitting or pin-holes) and the specified minimum yield strength (SMYS) ofthe pipe is not more than 40,000 psig (275,800 kPa), a tempo-rary repair may be made by fillet welding a properly designedsplit coupling or plate patch over the pitted area. (See 8.2.3for design considerations and Appendix C for an example.)The material for the repair shall match the base metal unlessapproved by the piping engineer.

For minor leaks, properly designed enclosures may bewelded over the leak while the piping system is in-service,provided the inspector is satisfied that adequate thicknessremains in the vicinity of the weld and the piping componentcan withstand welding without the likelihood of further mate-rial damage, such as from caustic service.

Temporary repairs should be removed and replaced with asuitable permanent repair at the next available maintenanceopportunity. Temporary repairs may remain in place for alonger period of time only if approved and documented bythe piping engineer.

8.1.3.2 Permanent Repairs

Repairs to defects found in piping components may bemade by preparing a welding groove that completely removesthe defect and then filling the groove with weld metal depos-ited in accordance with 8.2.

Corroded areas may be restored with weld metal depositedin accordance with 8.2. Surface irregularities and contamina-tion shall be removed before welding. Appropriate NDEmethods shall be applied after completion of the weld.

If it is feasible to take the piping system out of service, thedefective area may be removed by cutting out a cylindricalsection and replacing it with a piping component that meetsthe applicable code.

Insert patches (flush patches) may be used to repair dam-aged or corroded areas if the following requirements are met:

a. Full-penetration groove welds are provided.b. For Class 1 and Class 2 piping systems, the welds shall be100 percent radiographed or ultrasonically tested using NDEprocedures that are approved by the inspector.c. Patches may be any shape but shall have rounded corners[1 inch (25 mm) minimum radius].

8.1.4 Nonwelding Repairs (On-Stream)

Temporary repairs of locally thinned sections or circum-ferential linear defects may be made on-stream by installing aproperly designed and fabricated bolted leak clamp. Thedesign shall include control of axial thrust loads if the pipingcomponent being clamped is (or may become) insufficient tocontrol pressure thrust. The effect of clamping (crushing)forces on the component also shall be considered.

During turnarounds or other appropriate opportunities,temporary leak sealing and leak dissipating devices, includ-ing valves, shall be removed and appropriate actions taken torestore the original integrity of the piping system. The inspec-tor and/or piping engineer shall be involved in determiningrepair methods and procedures.

Procedures that include leak sealing fluids (“pumping”) forprocess piping should be reviewed for acceptance by theinspector or piping engineer. The review should take into con-



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

8-2 API 570

sideration the compatibility of the sealant with the leakingmaterial; the pumping pressure on the clamp (especially whenrepumping); the risk of sealant affecting downstream flowmeters, relief valves, or machinery; the risk of subsequent leak-age at bolt threads causing corrosion or stress corrosion crack-ing of bolts; and the number of times the seal area is repumped.

8.2 WELDING AND HOT TAPPING

All repair and alteration welding shall be done in accor-dance with the principles of ASME B31.3 or the code towhich the piping system was built.

Any welding conducted on piping components in opera-tion must be done in accordance with API Publ 2201. Theinspector shall use as a minimum the “Suggested Hot TapChecklist” contained in API Publication 2201 for hot tappingperformed on piping components.

8.2.1 Procedures, Qualifications, and Records

The repair organization shall use welders and welding pro-cedures qualified in accordance with ASME B31.3 or thecode to which the piping was built.

The repair organization shall maintain records of weldingprocedures and welder performance qualifications. Theserecords shall be available to the inspector prior to the start ofwelding.

8.2.2 Preheating and Postweld Heat Treatment

8.2.2.1 Preheating

Preheat temperature used in making welding repairs shallbe in accordance with the applicable code and qualified weld-ing procedure. Exceptions for temporary repairs must beapproved by the piping engineer.

Preheating to not less than 300°F (150°C) may be consid-ered as an alternative to postweld heat treatment (PWHT) foralterations or repairs of piping systems initially postweld heattreated as a code requirement (see note). This applies to pip-ing constructed of the P-1 steels listed in ASME B31.3. P-3steels, with the exception of Mn-Mo steels, also may receivethe 300°F (150°C) minimum preheat alternative when thepiping system operating temperature is high enough to pro-vide reasonable toughness and when there is no identifiablehazard associated with pressure testing, shutdown, and star-tup. The inspector should determine that the minimum pre-heat temperature is measured and maintained. After welding,the joint should immediately be covered with insulation toslow the cooling rate.

Note: Preheating may not be considered as an alternative to environ-mental cracking prevention.

Piping systems constructed of other steels initially requir-ing PWHT normally are postweld heat treated if alterations orrepairs involving pressure retaining welding are performed.The use of the preheat alternative requires consultation with

the piping engineer who should consider the potential forenvironmental cracking and whether the welding procedurewill provide adequate toughness. Examples of situationswhere this alternative could be considered include seal welds,weld metal buildup of thin areas, and welding support clips.

8.2.2.2 Postweld Heat Treatment

PWHT of piping system repairs or alterations should bemade using the applicable requirements of ASME B31.3 orthe code to which the piping was built. See 8.2.2.1 for analternative preheat procedure for some PWHT requirements.Exceptions for temporary repairs must be approved by thepiping engineer.

Local PWHT may be substituted for 360-degree bandingon local repairs on all materials, provided the following pre-cautions and requirements are applied:

a. The application is reviewed, and a procedure is developedby the piping engineer.b. In evaluating the suitability of a procedure, considerationshall be given to applicable factors, such as base metal thick-ness, thermal gradients, material properties, changes resultingfrom PWHT, the need for full-penetration welds, and surfaceand volumetric examinations after PWHT. Additionally, theoverall and local strains and distortions resulting from theheating of a local restrained area of the piping wall shall beconsidered in developing and evaluating PWHT procedures.c. A preheat of 300°F (150°C), or higher as specified by spe-cific welding procedures, is maintained while welding.d. The required PWHT temperature shall be maintained for adistance of not less than two times the base metal thicknessmeasured from the weld. The PWHT temperature shall bemonitored by a suitable number of thermocouples (a mini-mum of two) based on the size and shape of the area beingheat treated.e. Controlled heat also shall be applied to any branch con-nection or other attachment within the PWHT area.f. The PWHT is performed for code compliance and not forenvironmental cracking resistance.

8.2.3 Design

Butt joints shall be full-penetration groove welds. Piping components shall be replaced when repair is likely

to be inadequate. New connections and replacements shall bedesigned and fabricated according to the principles of theapplicable code. The design of temporary enclosures andrepairs shall be approved by the piping engineer.

New connections may be installed on piping systems pro-vided the design, location, and method of attachment con-form to the principles of the applicable code.

Fillet-welded patches require special design consider-ations, especially relating to weld-joint efficiency and crevicecorrosion. Fillet-welded patches shall be designed by the pip-ing engineer. A patch may be applied to the external surfaces



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

P

IPING

I

NSPECTION

C

ODE

—I

NSPECTION

, R

EPAIR

, A

LTERATION

,

AND

R

ERATING

OF

I

N

-S

ERVICE

P

IPING

S

YSTEMS

8-3

of piping, provided it is in accordance with 8.1.3 and meetseither of the following requirements:

a. The proposed patch provides design strength equivalent to areinforced opening designed according to the applicable code.b. The proposed patch is designed to absorb the membranestrain of the part in a manner that is in accordance with theprinciples of the applicable code, if the following criteria aremet:

1. The allowable membrane stress is not exceeded in thepiping part or the patch.2. The strain in the patch does not result in fillet weldstresses exceeding allowable stresses for such welds.3. An overlay patch shall have rounded corners (seeAppendix C).

8.2.4 Materials

The materials used in making repairs or alterations shallbe of known weldable quality, shall conform to the applicablecode, and shall be compatible with the original material. Formaterial verification requirements, see 5.8.

8.2.5 Nondestructive Examination

Acceptance of a welded repair or alteration shall includeNDE in accordance with the applicable code and the owner/user’s specification, unless otherwise specified in API 570.

8.2.6 Pressure Testing

After welding is completed, a pressure test in accordancewith 5.7 shall be performed if practical and deemed necessaryby the inspector. Pressure tests are normally required afteralterations and major repairs. When a pressure test is not nec-essary or practical, NDE shall be utilized in lieu of a pressuretest. Substituting appropriate NDE procedures for a pressuretest after an alteration or repair may be done only after con-sultation with the inspector and the piping engineer.

When it is not practical to perform a pressure test of a finalclosure weld that joins a new or replacement section of pipingto an existing system, all of the following requirements shallbe satisfied:

a. The new or replacement piping is pressure tested andexamined in accordance with the applicable code governingthe design of the piping system, or if not practical, welds areexamined with appropriate NDE, as specified by the autho-rized piping inspector. b. The closure weld is a full-penetration butt-weld betweenany pipe or standard piping component of equal diameter andthickness, axially aligned (not miter cut), and of equivalentmaterials. Acceptable alternatives are: (1) slip-on flanges fordesign cases up to Class 150 and 500°F, (260°C) and (2)socket welded flanges or socket welded unions for sizes NPS2 or less and design cases up to Class 150 and 500°F (260°C).A spacer designed for socket welding or some other meansshall be used to establish a minimum

1

/

16

inch (1.6 mm) gap.

Socket welds shall be per ASME B31.3 and shall be a mini-mum of two passes. c. Any final closure butt-weld shall be of 100-percent radio-graphic quality; or angle-beam ultrasonics flaw detection maybe used, provided the appropriate acceptance criteria havebeen established.d. MT or PT shall be performed on the root pass and thecompleted weld for butt-welds and on the completed weld forfillet-welds.

The owner/user shall specify industry-qualified UT shearwave examiners for closure welds that have not been pressuretested and for weld repairs identified by the piping engineeror authorized inspector. The requirement for use of industry-qualified UT shear wave examiners becomes effective twoyears after publication in this code or addendum.

8.3 RERATING

Rerating piping systems by changing the temperature rat-ing or the MAWP may be done only after all of the followingrequirements have been met:

a. Calculations are performed by the piping engineer or theinspector.b. All reratings shall be established in accordance with therequirements of the code to which the piping system was builtor by computation using the appropriate methods in the latestedition of the applicable code.c. Current inspection records verify that the piping system issatisfactory for the proposed service conditions and that theappropriate corrosion allowance is provided.d. Rerated piping systems shall be leak tested in accordancewith the code to which the piping system was built or the lat-est edition of the applicable code for the new serviceconditions, unless documented records indicate a previousleak test was performed at greater than or equal to the testpressure for the new condition. An increase in the rating tem-perature that does not affect allowable tensile stress does notrequire a leak test.e. The piping system is checked to affirm that the requiredpressure relieving devices are present, are set at the appropri-ate pressure, and have the appropriate capacity at set pressure.f. The piping system rerating is acceptable to the inspectoror piping engineer.g. All piping components in the system (such as valves,flanges, bolts, gaskets, packing, and expansion joints) areadequate for the new combination of pressure andtemperature.h. Piping flexibility is adequate for design temperaturechanges.i. Appropriate engineering records are updated.j. A decrease in minimum operating temperature is justifiedby impact test results, if required by the applicable code.

03

03

03

01



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

9-1

SECTION 9—INSPECTION OF BURIED PIPING

Inspection of buried process piping (not regulated by theDepartment of Transportation) is different from other processpiping inspection because significant external deteriorationcan be caused by corrosive soil conditions. Since the inspec-tion is hindered by the inaccessibility of the affected areas ofthe piping, the inspection of buried piping is treated in a sepa-rate section of API 570. Important, nonmandatory referencesfor underground piping inspection are the following NACEdocuments: RP0169, RP0274, and RP0275; and Section 11of API RP 651.

9.1 TYPES AND METHODS OF INSPECTION

9.1.1 Above-Grade Visual Surveillance

Indications of leaks in buried piping may include a changein the surface contour of the ground, discoloration of the soil,softening of paving asphalt, pool formation, bubbling waterpuddles, or noticeable odor. Surveying the route of buriedpiping is one method of identifying problem areas.

9.1.2 Close-Interval Potential Survey

The close-interval potential survey performed at groundlevel over the buried pipe can be used to locate active corro-sion points on the pipe’s surface.

Corrosion cells can form on both bare and coated pipewhere the bare steel contacts the soil. Since the potential atthe area of corrosion will be measurably different from anadjacent area on the pipe, the location of the corrosion activ-ity can be determined by this survey technique.

9.1.3 Pipe Coating Holiday Survey

The pipe coating holiday survey can be used to locatecoating defects on buried coated pipes, and it can be used onnewly constructed pipe systems to ensure that the coating isintact and holiday-free. More often it is used to evaluate coat-ing serviceability for buried piping that has been in-servicefor an extended period of time.

From survey data, the coating effectiveness and rate ofcoating deterioration can be determined. This informationis used both for predicting corrosion activity in a specificarea and for forecasting replacement of the coating for cor-rosion control.

9.1.4 Soil Resistivity

Corrosion of bare or poorly coated piping is oftencaused by a mixture of different soils in contact with thepipe surface. The corrosiveness of the soils can be deter-mined by a measurement of the soil resistivity. Lower lev-els of resistivity are relatively more corrosive than higherlevels, especially in areas where the pipe is exposed to sig-nificant changes in soil resistivity.

Measurements of soil resistivity should be performedusing the Wenner Four-Pin Method in accordance with ASTMG57. In cases of parallel pipes or in areas of intersecting pipe-lines, it may be necessary to use the Single-Pin Method toaccurately measure the soil resistivity. For measuring resistiv-ity of soil samples from auger holes or excavations, a soil boxserves as a convenient means for obtaining accurate results.

The depth of the piping shall be considered in selecting themethod to be used and the location of samples. The testingand evaluation of results should be performed by personneltrained and experienced in soil resistivity testing.

9.1.5 Cathodic Protection Monitoring

Cathodically protected buried piping should be monitoredregularly to assure adequate levels of protection. Monitoringshould include periodic measurement and analysis of pipe-to-soil potentials by personnel trained and experienced in cathodicprotection system operation. More frequent monitoring of criti-cal cathodic protection components, such as impressed currentrectifiers, is required to ensure reliable system operation.

Refer to NACE RP0169 and Section 11 of API RP 651 forguidance applicable to inspecting and maintaining cathodicprotection systems for buried piping.

9.1.6 Inspection Methods

Several inspection methods are available. Some methodscan indicate the external or wall condition of the piping,whereas other methods indicate only the internal condition.Examples are as follows:

a. Intelligent pigging. This method involves the movement ofa device (pig) through the piping either while it is in-serviceor after it has been removed from service. Several types ofdevices are available employing different methods of inspec-tion. The line to be evaluated must be free from restrictionsthat would cause the device to stick within the line. Fivediameter bends are usually required since standard 90-degreepipe ells may not pass a pig. The line must also have facilitiesfor launching and recovering the pigs.b. Video cameras. Television cameras are available that canbe inserted into the piping. These cameras may provide visualinspection information on the internal condition of the line.c. Excavation. In many cases, the only available inspectionmethod that can be performed is unearthing the piping in orderto visually inspect the external condition of the piping and toevaluate its thickness and internal condition using the methodsdiscussed in 5.4.2. Care should be exercised in removing soilfrom above and around the piping to prevent damaging theline or line coating. The last few inches (mm) of soil should beremoved manually to avoid this possibility. If the excavation issufficiently deep, the sides of the trench should be properlyshored to prevent their collapse, in accordance with OSHA



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

9-2 API 570

regulations, where applicable. If the coating or wrapping isdeteriorated or damaged, it should be removed in that area toinspect the condition of the underlying metal.

9.2 FREQUENCY AND EXTENT OF INSPECTION

9.2.1 Above-Grade Visual Surveillance

The owner/user should, at approximately 6-month inter-vals survey the surface conditions on and adjacent to eachpipeline path (see 9.1.1).

9.2.2 Pipe-to-Soil Potential Survey

A close-interval potential survey on a cathodically pro-tected line may be used to verify that the buried piping has aprotective potential throughout its length. For poorly coatedpipes where cathodic protection potentials are inconsistent,the survey may be conducted at 5-year intervals for verifica-tion of continuous corrosion control.

For piping with no cathodic protection or in areas whereleaks have occurred due to external corrosion, a pipe-to-soilpotential survey may be conducted along the pipe route. Thepipe should be excavated at sites where active corrosion cellshave been located to determine the extent of corrosion dam-age. A continuous potential profile or a close-interval surveymay be required to locate active corrosion cells.

9.2.3 Pipe Coating Holiday Survey

The frequency of pipe coating holiday surveys is usuallybased on indications that other forms of corrosion control areineffective. For example, on a coated pipe where there isgradual loss of cathodic protection potentials or an externalcorrosion leak occurs at a coating defect, a pipe coating holi-day survey may be used to evaluate the coating.

9.2.4 Soil Corrosivity

For piping buried in lengths greater than 100 feet (30 m)and not cathodically protected, evaluations of soil corrosivityshould be performed at 5-year intervals. Soil resistivity mea-surements may be used for relative classification of the soilcorrosivity (see 9.1.4). Additional factors that may warrantconsideration are changes in soil chemistry and analyses of thepolarization resistance of the soil and piping interface.

9.2.5 Cathodic Protection

If the piping is cathodically protected, the systemshould be monitored at intervals in accordance with Sec-tion 10 of NACE RP0169 or Section 11 of API RP 651.

9.2.6 External and Internal Inspection Intervals

If internal corrosion of buried piping is expected as a resultof inspection on the above-grade portion of the line, inspec-tion intervals and methods for the buried portion should beadjusted accordingly. The inspector should be aware of and

consider the possibility of accelerated internal corrosion indeadlegs.

The external condition of buried piping that is not cathodi-cally protected should be determined by either pigging, whichcan measure wall thickness, or by excavating according to thefrequency given in Table 9-1. Significant external corrosiondetected by pigging or by other means may require excavationand evaluation even if the piping is cathodically protected.

Piping inspected periodically by excavation shall beinspected in lengths of 6 feet–8 feet (2.0 m–2.5 m) at one ormore locations judged to be most susceptible to corrosion.Excavated piping should be inspected full circumference forthe type and extent of corrosion (pitting or general) and thecondition of the coating.

If inspection reveals damaged coating or corroded piping,additional piping shall be excavated until the extent of thecondition is identified. If the average wall thickness is at orbelow retirement thickness, it shall be repaired or replaced.

If the piping is contained inside a casing pipe, the condi-tion of the casing should be inspected to determine if waterand/or soil has entered the casing. The inspector should verifythe following: (a) both ends of the casing extend beyond theground line; (b) the ends of the casing are sealed if the casingis not self-draining; and, (c) the pressure-carrying pipe isproperly coated and wrapped.

9.2.7 Leak Testing Intervals

An alternative or supplement to inspection is leak testingwith liquid at a pressure at least 10 percent greater than maxi-mum operating pressure at intervals one-half the length ofthose shown in Table 9-1 for piping not cathodically protectedand at the same intervals as shown in Table 9-1 for cathodi-cally protected piping. The leak test should be maintained fora period of 8 hours. Four hours after the initial pressurizationof the piping system, the pressure should be noted and, if nec-essary, the line repressurized to original test pressure and iso-lated from the pressure source. If, during the remainder of thetest period, the pressure decreases more than 5 percent, thepiping should be visually inspected externally and/orinspected internally to find the leak and assess the extent ofcorrosion. Sonic measurements may be helpful in locatingleaks during leak testing.

Buried piping also may be surveyed for integrity by usingtemperature-corrected volumetric or pressure test methods.

Table 9-1—Frequency of Inspection for Buried Piping Without Effective Cathodic Protection

Soil Resistivity (ohm-cm) Inspection Interval (years)

< 2,000 52,000 to 10,000 10

> 10,000 15



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

P

IPING

I

NSPECTION

C

ODE

—I

NSPECTION

, R

EPAIR

, A

LTERATION

,

AND

R

ERATING

OF

I

N

-S

ERVICE

P

IPING

S

YSTEMS

9-3

Other alternative leak test methods involve acoustic emissionexamination and the addition of a tracer fluid to the pressur-ized line (such as helium or sulfur hexafloride). If the tracer isadded to the service fluid, the owner/user shall confirm suit-ability for process and product.

9.3 REPAIRS TO BURIED PIPING SYSTEMS

9.3.1 Repairs to Coatings

Any coating removed for inspection shall be renewed andinspected appropriately.

For coating repairs, the inspector should be assured thatthe coating meets the following criteria:

a. It has sufficient adhesion to the pipe to prevent underfilmmigration of moisture.b. It is sufficiently ductile to resist cracking.c. It is free of voids and gaps in the coating (holidays).d. It has sufficient strength to resist damage due to handlingand soil stress.e. It can support any supplemental cathodic protection.

In addition, coating repairs may be tested using a high-voltage holiday detector. The detector voltage shall beadjusted to the appropriate value for the coating material andthickness. Any holidays found shall be repaired and retested.

9.3.2 Clamp Repairs

If piping leaks are clamped and reburied, the location ofthe clamp shall be logged in the inspection record and may besurface marked. Both the marker and the record shall note thedate of installation and the location of the clamp. All clampsshall be considered temporary. The piping should be perma-nently repaired at the first opportunity.

9.3.3 Welded Repairs

Welded repairs shall be made in accordance in 8.2.

9.4 RECORDS

Record systems for buried piping should be maintained inaccordance with 7.6. In addition, a record of the location anddate of installation of temporary clamps shall be maintained



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

A-1

APPENDIX A—INSPECTOR CERTIFICATION

A.1 Examination

A written examination to certify inspectors within thescope of API 570,

Piping Inspection Code, Inspection,Repair, Alteration, and Rerating of In–Service Piping Sys-tems

, shall be administered by API or a third party designatedby the API. The examination shall be based on the currentAPI Body of Knowledge as published by API.

A.2 Certification

A.2.1

An API 570 authorized piping inspector certificatewill be issued when an applicant has successfully passed theAPI certification exam and satisfies the criteria for experienceand education. His/her education and experience, when com-bined, shall be equal to at least one of the following:

a. A Bachelor of Science degree in engineering or technol-ogy, plus one year of experience in supervision of inspectionactivities or performance of inspection activities as describedin API 570.

b. A two year degree or certificate in engineering or technol-ogy, plus two years of experience in the design, construction,repair, inspection, or operation of piping systems, of which onyear must be in supervision of inspection activities or perfor-mance of inspection activities as described in API 570.

c. A high school diploma or equivalent, plus three years ofexperience in the design, construction, repair, inspection, oroperation of piping systems, of which one year must be insupervision of inspection activities or performance of inspec-tion activities as described in API 570.

d. A minimum of five years of experience in the design, con-struction, repair, inspection, or operation of piping systems,of which on year must be in supervision of inspection activi-ties or performance of inspection activities as described inAPI 570.

A.2.2

An API authorized piping inspector certificate isvalid for three years from its date of issuance.

A.2.3

An API inspector certification will be valid in alljurisdictions and any other location that accepts or otherwisedoes not prohibit the use of API 570.

A.3 Certification Agency

The American Petroleum Institute shall be the certifyingagency.

A.4 Retroactivity

The certification requirements of API 570 shall not be ret-roactive or interpreted as applying before twelve months afterthe date of publication of this edition or addendum to API570. The recertification requirements of API 570 A.5.2 shallnot be retroactive or interpreted as applying before 3 yearsafter the date of publication of this edition or addendum toAPI 570.

A.5 Recertification

A.5.1

Recertification is required three years from the dateof issuance of the API 570 authorized piping inspector certifi-cate. Recertification by written examination will be requiredfor authorized piping inspectors who have not been activelyengaged as authorized piping inspectors within the mostrecent three-year certification period and for authorized pip-ing inspectors who have not previously passed the exam.Exams will be in accordance with all provisions contained inAPI 570.

A.5.2

“Actively engaged as an authorized piping inspector”shall be defined as a minimum of 20% of time spent perform-ing inspection activities or supervision inspection activities asdescribed in the API 570 over the most recent three year certi-fication period.

Note: Inspection activities common to other API inspection docu-ments (NDE, record-keeping, review, of welding documents, etc.)may be considered here.

A.5.3

Once every other recertification period, (every sixyears) inspectors actively engaged as an authorized pipinginspector shall demonstrate knowledge of revisions to API570 that were instituted during the previous six years. Thisrequirement shall be effective six years from the inspector’sinitial certification date. Inspectors who have not beenactively engaged as an authorized piping inspector within themost recent three-year certification period shall recertify asrequired in A.5.1.

03

00

03



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

B-1

APPENDIX B—TECHNICAL INQUIRIES

B.1 Introduction

API will consider written requests for interpretations ofAPI 570. API staff will make such interpretations in writingafter consultation, if necessary, with the appropriate commit-tee officers and the committee membership. The API commit-tee responsible for maintaining API 570 meets regularly toconsider written requests for interpretations and revisions,and to develop new criteria as dictated by technologicaldevelopment. The committee’s activities in this regard arelimited strictly to interpretations of the latest edition of API570 or to the consideration of revisions to API 570 based onthe new data or technology.

As a matter of policy, API does not approve, certify, rate,or endorse any item, construction, proprietary device, oractivity; and accordingly, inquiries requiring such consider-ation will be returned. Moreover, API does not act as a con-sultant on specific engineering problems or on the generalunderstanding or application of the rules. If, based on theinquiry information submitted, it is the opinion of the com-mittee that the inquirer should seek engineering or technicalassistance, the inquiry will be returned with the recommenda-tion that such assistance be obtained.

All inquiries that do not provide the information neededfor full understanding will be returned.

B.2 Inquiry Format

Inquiries shall be limited strictly to requests for interpreta-tion of the latest edition of API 570 or to the consideration of

revisions to API 570 based on new data or technology. Inquir-ies shall be submitted in the following format:

a. Scope—The inquiry shall involve a single subject orclosely related subjects. An inquiry letter concerning unre-lated subjects will be returned.

b. Background—The inquiry letter shall state the purpose ofthe inquiry, which shall be either to obtain an interpretation ofAPI 570 or to propose consideration of a revision to API 570.The letter shall provide concisely the information needed forcomplete understanding of the inquiry (with sketches, as nec-essary) and include references to the applicable edition,revision, paragraphs, figures, and tables.

c. Inquiry—The inquiry shall be stated in a condensed andprecise question format, omitting superfluous backgroundinformation and, where appropriate, composed in such away that “yes” or “no” (perhaps with provisos) would be asuitable reply. This inquiry statement should be technicallyand editorially correct. The inquirer shall state what he orshe believes API 570 requires. If in the opinion of theinquirer a revision to API 570 is needed, the inquirer shallprovide recommended wording.

Submit the inquiry in typewritten form; however, legiblyhandwritten inquiries will be considered. Include the nameand the mailing address of the inquirer. Submit the proposalto the following address: director of the Standards Depart-ment, American Petroleum Institute, 1220 L Street, N.W.,Washington, D.C. 20005, [email protected].

01



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

C-1

APPENDIX C—EXAMPLES OF REPAIRS

C.1 Repairs

Manual welding utilizing the gas metal-arc or shieldedmetal-arc processes may be used.

When the temperature is below 50°F (10°C), low-hydro-gen electrodes, AWS E-XX16 or E-XX18, shall be used whenwelding materials conforming to ASTM A-53, Grades A andB; A-106, Grades A and B; A-333; A-334; API 5L; and othersimilar material. These electrodes should also be used onlower grades of material when the temperature of the materialis below 32°F (0°C). The piping engineer should be consultedfor cases involving different materials.

When AWS E-XX16 or E-XX18 electrodes are used onweld numbers 2 and 3 (see Figure C-1 below), the beads shallbe deposited by starting at the bottom of the assembly andwelding upward. The diameter of these electrodes should notexceed

5

/

32

inch (4.0 mm). Electrodes larger that

5

/

32

inch(4.0 mm) may be used on weld number 1 (see Figure C-1),but the diameter should not exceed

3

/

16

inch (4.8 mm). The longitudinal welds (number 1, Figure C-1) on the

reinforcing sleeve shall be fitted with a suitable tape or mild

steel backing strip (see note) to avoid fusing the weld to theside wall of the pipe.

Note: If the original pipe along weld number 1 has been checkedthoroughly by ultrasonic methods and it is of sufficient thickness forwelding, a backing strip is not necessary.

All repair and welding procedures for on-stream linesmust conform to API Publ 2201.

C.2 Small Repair Patches

The diameter of electrodes should not exceed

5

/

32

inch(4.0 mm). When the temperature of the base material is below32°F (0°C), low-hydrogen electrodes shall be used. Weavingof weld beads deposited with low-hydrogen electrodes shouldbe avoided.

All repair and welding procedures for on-stream linesmust conform to API Publication 2201.

Examples of small repair patches are shown below inFigure C-2.

Figure C-1—Encirclement Repair Sleeve

13 2

Appropriate gasket material



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

C-2 API 570

Figure C-2—Small Repair Patches

1" (25 mm) minimum radius

Size of the patch should not exceed 1/2 the pipe diameter.A full encirclement sleeve should be used if the corrodedarea exceeds 1/2 the diameter.



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

D-1

APPENDIX D—EXTERNAL INSPECTION CHECKLIST FOR PROCESS PIPING

D.1 External Inspection Checklist for Process Piping

Publication Title # Date InspectedItem Inspected By Status

a. Leaks.1. Process.2. Steam Tracing.3. Existing Clamps.

b. Misalignment.1. Piping misalignment/restricted movement.2. Expansion joint misalignment.

c. Vibration.1. Excessive overhung weight.2. Inadequate support.3. Thin, small-bore, or alloy piping.4. Threaded connections.5. Loose supports causing metal wear.

d. Supports.1. Shoes off support.

2. Hanger distortion or breakage.3. Bottomed-out springs.4. Brace distortion/breakage.5. Loose brackets.6. Slide plates/rollers.7. Counter balance condition.8. Support corrosion.

e. Corrosion.1. Bolting support points under clamps.2. Coating/Painting deterioration.3. Soil-to-air interface.4. Insulation interfaces.5. Biological growth.

f. Insulation.1. Damage/penetrations.2. Missing jacketing/insulation.3. Sealing deterioration.4. Bulging.5. Banding (broken/missing).



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

08/03



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---

Additional copies are available through Global EngineeringDocuments at (800) 854-7179 or (303) 397-7956

Information about API Publications, Programs and Services isavailable on the World Wide Web at: http://www.api.org

Order No. C570A3



--``,,`,,,```,`,,,`,,-`-`,,`,,`,`,,`---